Guest Post – pv magazine USA: Recent Episodes

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Data-driven strategies and advanced analytics are revolutionizing solar operations and maintenance. These insights are supported by a study from the National Renewable Energy Laboratory on availability and performance loss factors for U.S. PV fleet systems.

As the solar industry continues its rapid growth, asset owners and operators face increasing challenges in maintaining and optimizing the performance of distributed portfolios. In recent webinar, experts from Wattch and Omnidian shed light on how data-driven strategies and advanced analytics are revolutionizing solar operations and maintenance (O&M). These insights are further supported by a comprehensive study from the National Renewable Energy Laboratory (NREL) on availability and performance loss factors for U.S. PV fleet systems.

The scale of the challenge

With the U.S. installing approximately 35 gigawatts of solar in 2023, the industry is grappling with a vast and growing fleet of assets that require ongoing care. Alex Nussey, co-founder and CEO of Wattch, highlighted the shift in focus: “For so long in the industry, there’s been so much focus on the leading edge of the growth curve, trying to get new assets on roofs and in the ground. But as these portfolios continue to grow and, importantly, start to age, O&M efficiency is becoming a lot more important.”

Additionally, the heterogeneity of these assets increases the complexity of managing distributed portfolios . “Not only are all of these assets geographically physically distributed, they’re also spread across various types of hardware and configurations . None of them are the same,” Nussey explained. This diversity in equipment, age, and location presents unique challenges for standardized O&M approaches. Operators need the ability to normalize data from multiple sources across their fleets to effectively surface, diagnose, prioritize, and address performance issues. .

From reactive to proactive: The power of data

Traditional O&M strategies often relied on reacting to fault codes or visible issues. However, this approach can either lead to unnecessary truck rolls or missed opportunities to correct subtle but significant performance issues. The webinar experts emphasized the importance of shifting to a data-driven, proactive model.

Trish Graf, VP of sales and strategic partnerships at Omnidian, outlined the potential impact: “The industry benchmark for truck rolls per megawatt is six truck rolls per megawatt over 12 to 48 months. We were able to reduce that by over two-thirds.”

This reduction is achieved through advanced analytics that can differentiate between critical issues that require immediate attention and less urgent issues that can be addressed during routine maintenance. “It’s less about remote diagnostics,” Graf explained, “and more about which problems really warrant a truck roll.”

System availability and performance

A recent NREL report, Availability and Performance Loss Factors for U.S. PV Fleet Systems, provides valuable insights into system availability and performance across a large fleet of PV systems. After analyzing data from 1,128 systems, researchers found that the median (P50) system availability was 0.991, with a lower 10th percentile (P90) value of 0.947. This means that half of the systems were available 99.1% of the time or more, while 90% of systems were available at least 94.7% of the time.

Performance index and degradation

The NREL study also examined the Performance Index (PI) of PV systems, which compares actual energy production to expected production based on weather conditions. After filtering out effects like snow and initial startup losses, the median system PI was found to be 0.95, indicating that the typical system produces about 95% of its expected energy.

System degradation is another critical factor in long-term performance. The NREL report compared multiple analysis methods and found that the median annual degradation rate ranged from -0.5% to -0.75% per year, depending on the methodology used. This is consistent with industry expectations but highlights the importance of accurate degradation modeling in financial projections.

Soiling impact

The NREL study provided new insights into soiling losses across different regions. Using the Combined Degradation and Soiling (CODS) analysis method, researchers analyzed 255 locations and found that annualized soiling losses typically range from 0-15%, with a median loss in the range of 2-3%. This data has been incorporated into an updated NREL soiling map, offering valuable information for system designers and operators.

The role of AI and machine learning

At the heart of modern data-driven O&M approaches are sophisticated platforms that leverage artificial intelligence (AI) and machine learning. Wattch’s platform, for instance, creates a “digital twin” of each solar asset, allowing for real-time comparison between actual and expected performance. By surfacing device-level and string-level expected voltage and current in addition to site-wide production, it helps operators understand and pinpoint areas of performance deviation to identify subcritical failures that might not be obvious to those looking at the data.

“We’re constantly watching every 10 seconds as data flows in from each site,” Nussey said. “We’re looking at that data and reassessing whether or not the site is still healthy, and if it is not, we can create an alert.”

This constant monitoring allows for early detection of issues, often before they significantly impact performance. Moreover, it enables more precise diagnosis, ensuring that when technicians are dispatched, they arrive with the right equipment and knowledge to resolve the issue efficiently.

Looking ahead

As the solar industry continues to mature, the role of data-driven O&M is set to grow. The experts predicted a future where predictive maintenance becomes the norm, where AI can forecast potential issues before they occur, and where O&M strategies are tailored to maximize financial performance rather than just technical metrics.

For asset owners and operators, embracing these data-driven approaches isn’t just about keeping up with technology—it’s about ensuring the long-term viability and profitability of their solar investments. As the industry scales up to meet ambitious clean energy goals, efficient, data-driven O&M will be crucial in maintaining the health and performance of the growing global solar fleet.

Tim Montague leads the Clean Power Consulting Group and is host of the Clean Power Hour podcast. He is a solar project developer, cleantech executive coach and consultant, mastermind group leader, entrepreneur and technology enthusiast.

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As we introduce more renewable energy into the mix, we must also address these challenges to ensure a reliable grid that can support the nation's clean energy goals. Nick Tumilowicz, director of product management, distributed energy management at Itron offers four solutions.

As the U.S. moves closer to its clean energy goals, solar power has emerged as a critical resource in reducing carbon emissions and fostering energy independence. With the Environmental Protection Agency (EPA) poised to distribute $7 billion in Solar for All grants, investments in rooftop solar panels, energy storage systems and community solar farms are set to accelerate. While these advancements signify progress, they also pose a crucial question: Can our aging power grid manage the heightened demand from intermittent solar energy?

The promise and challenge of solar power

Renewable energy sources, particularly solar, offer immense potential to transform our energy landscape. Solar energy is abundant, sustainable and cost effective. However, it presents unique challenges for grid management. Unlike conventional power plants that provide a steady flow of electricity, solar power is variable. Solar panels only generate electricity when the sun is shining, which means energy production fluctuates throughout the day and is subject to weather conditions. This intermittency can introduce complexities in maintaining power quality and reliability.

For an already strained and aging grid, the surge in solar adoption raises concerns. How do we maintain a stable energy supply when solar energy is unpredictable? How do we ensure power quality amid such fluctuations? As we introduce more renewable energy into the mix, we must also address these challenges to ensure a reliable grid that can support the nation’s clean energy goals.

The aging grid: Struggling to keep pp

Many parts of the U.S. grid infrastructure were built decades ago, and the systems in place were not designed to manage modern energy demands—let alone the complexities of renewable integration. In some regions, grids are already stretched to their limits, struggling with reliability issues and outages. The increased adoption of solar power, along with other distributed energy resources (DERs), will only amplify these pressures.

One of the key issues is balancing supply and demand. In traditional grid systems, energy flows from centralized power plants to consumers in a predictable and controllable manner. But with the rise of solar power, electricity flows can reverse, sending power from rooftops and solar farms back to the grid. While this is a positive development, it creates technical challenges for grid operators who need to balance energy inputs and outputs to avoid voltage fluctuations and power quality issues.

Ensuring power quality and reliability

So, how can we ensure that the grid remains stable and reliable as solar adoption continues to grow? Here are a few critical strategies:

1. Modernizing grid infrastructure

The first and perhaps most obvious solution is to invest in modernizing the grid. This means upgrading transmission lines, substations and distribution systems to be more adaptable and resilient. Although this is a long-term and capital-intensive process, it’s crucial for creating a grid that can manage renewable energy sources effectively.

Investments in smart grid technologies are a key part of this modernization effort. Smart grids can respond dynamically to fluctuations in energy supply and demand, automatically adjusting to maintain grid stability. With advanced sensors and automation, smart grids can also detect and isolate problems before they lead to widespread outages, reducing downtime and improving overall reliability.

1. Energy storage: The key to smoothing intermittency

Energy storage solutions, such as batteries, are critical for mitigating the intermittency of solar power. Batteries are also the fastest-growing secondary electricity source for the grid, according to recently published data from the Energy Information Administration (EIA). By storing excess solar energy generated during the day, batteries allow that energy to be used later when the sun isn’t shining. This helps balance supply and demand on the grid and ensures a steady flow of electricity, even when renewable generation dips.

Grid-scale energy storage, along with smaller distributed storage systems, plays a crucial role in stabilizing the grid. As more solar resources are deployed, energy storage will need to be widely implemented to manage the variable nature of solar power effectively. The EPA’s “Solar for All” grants, which include funding for energy storage projects, could significantly accelerate this process.

1. Leveraging data and advanced analytics

In addition to modernizing hardware, we must also focus on using data to optimize grid operations. By leveraging advanced analytics and real-time monitoring, utilities can better predict energy production patterns from solar installations and make proactive adjustments to maintain grid stability. This predictive approach enables more efficient energy management and reduces the likelihood of disruptions.

Advanced data analytics can also provide insight into how different parts of the grid respond to solar power, enabling utilities to fine-tune their operations. For example, utilities can identify areas with high solar penetration and deploy targeted solutions, such as voltage regulators or enhanced storage, to ensure power quality in those regions.

1. Enhancing grid flexibility

As the energy landscape evolves, grid flexibility becomes more important. A flexible grid can accommodate a wide range of energy sources, from large solar farms to residential rooftop systems, and can adjust quickly to changes in supply and demand. Enhancing flexibility requires not only physical upgrades but also regulatory and market changes that incentivize distributed energy resource integration.

Demand response programs, which encourage consumers to adjust their energy use based on grid conditions, are one way to enhance flexibility. By shifting energy consumption to times when solar production is high, these programs can help reduce strain on the grid and make it easier to manage solar resources.

The path forward

The grid is the backbone of our energy system, and its ability to adapt to the influx of solar power will determine the success of our clean energy transition. While significant challenges lie ahead, clear strategies can ensure that our grid remains stable, reliable and capable of supporting a sustainable energy future.

As solar adoption grows, so too must our grid’s ability to handle its intermittency. By investing in modernization, advocating for policy changes and leveraging technological advancements, we can build a resilient grid that not only supports the surge in solar power but also powers a cleaner, greener future for generations to come.

Nick Tumilowicz is director of product management, distributed energy management, Itron, a U.S.-based technology company that offers products and services for energy and water resource management.

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In this series outlining the process of building a truly sustainable home, much has happened while waiting for a building permit... and the building is set to begin.

Since my last article in this series more than 6 months ago, it feels like there’s been a lot of waiting and not much progress, but just the other week, I got approval to move forward with my build. But now when I look back on those past months, I see how much work was achieved. And now, all of a sudden, everything is coming together and building has started.

First, we went through a redesign that included going back to my original floorplan sketch and making significant changes to meet Passive House Institute US (PHIUS) standards. One of the most crucial redesigns was to change the wall design for improved insulation, air sealing and moisture management.

Additionally, this new design also included an extended roof concept where the truss overhangs were designed to be at just the right height and length to allow for direct sunlight in the winter when the sun is low in the sky for passive heating and shading in the summer when the sun is high in the sky.

As part of the layout redesign we chose to centralize the HVAC system in order improve the circulation of hot/cold air. This ensures a more consistent temperature throughout the house (i.e., preventing hot and cold spots), and minimizes energy transmission from the Energy Recovery Ventilators (ERV) outside air ductwork. This new design was then sent to a PHIUS Certified Passive House Consultant (CPHC) to analyze the house’s energy footprint. Based on the modeling software, the new design should meet the performance specifications! We are now working through the certification process.

While my builder led the PHIUS process, I researched water efficiency and conservation opportunities. While I hoped to leverage water recycling and reuse techniques, this has proven significantly more complex. Since the land does not have a water utility connection, the house will have a well and septic tank. Wanting to find opportunities to reuse grey water, I looked for relevant technologies and techniques. At every turn, another problem popped up. Storing or reusing grey water for second use can be particularly problematic.

One particularly common usage is diverting water from the laundry machine for gardening. However, even if using all natural cleaning supplies, the chemicals and dyes in our clothes can be toxic and are not recommended for use in an edible garden. I also looked for water experts, but found that there are not many professional services available, and most of the options are DIY.

During a lecture I attended as part of the local chapter of the Climate Reality Project, I learned that garbage disposals are some of the biggest causes of greenhouse gasses (GHG) in our water system, but I was already planning on composting. As of now, the two main ways that I plan on conserving water is to install a toilet tank sink and having a rain catchment system for gardening purposes. If anyone can offer any additional advice, please reach out.

Speaking or getting advice from readers – After one of my first articles, someone got in touch with me about his experience building a similar type of sustainable home and mentioned that one of the biggest challenges during his build was how the window and door delivery timeline delayed the rest of the build. Since most window manufacturers in the U.S. do not target Passive House specifications, finding windows can include working with manufacturers outside of the U.S. After considering importing windows, he recommended to plan for a long delivery time. Luckily, my expert builder is ahead of the game when it comes to project management as this was the very first action we took.

After picking out the doors and windows, I needed to also start thinking about the different selections and styles for the interior design of the house. I began working with Bound Collaborative, an interior design studio that focuses on designing within and beyond bounds for healthier people and planet. The two creative female co-founders, Erin and Jamey, are helping me identify and define my interior aesthetic and create a style guide, while staying environmentally conscious and using healthy materials and products.

I also dug into the yard, both figuratively and literally. I had put together my vision for a small homestead during my terra.do Soil Health and Regenerative Farming course that included a large edible garden, various coniferous and deciduous trees, and fruit and flowering trees, plus cover crops or prairie flowers. So, I started reaching out to experts to help me with the first steps. I’ll dive more into that process and the experts who are guiding me in a future article, but for now, I’ve identified that the land was previously used to grow corn and sent a bunch of soil samples to the University of Minnesota for analysis.

Some other logistics that were taking place in the background, were updating land insurance to start the build, completing the staking for the house and septic tank, and sending the designs into the county for review and approval. After some tweaks, such as adding a highwater mark and grading, I’ve finally got approval to start building.

Read the first in the series Building not your average dream home.

Jessica Fishman, director of renewable energy at Kiterocket, is a strategic marketing leader with nearly 20 years’ experience, including seven years as head of global public and media relations at inverter maker SolarEdge. Passionate about addressing climate change by accelerating the clean energy transition, she has worked at leading renewables companies, building marketing and communications departments.

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One solution is to aggregate distributed energy resources with energy management systems and energy storage, into virtual power plants, which are proving their worth as key players in increasing grid capacity and balancing the grid.

In the recent 2025-26 capacity auction for PJM, the nation’s largest grid operator serving the mid-Atlantic and Midwest, the auction price hit a record high of $269.92/MW-day. That’s up 10 times from the $28.92/MW-day price for 2024-25.

Supply isn’t meeting demand

Why did prices go so high? A number of factors contributed to a mismatch between supply and demand.

Supply is low due in part to power producers exiting the generation market and in part to fossil-fuel-powered plant retirements. Since the 2024-25 timeframe, about 6.6 GW of generation in the region has retired or is expected to retire, and PJM expects up to 40 GW, or 21% of the region’s installed capacity, to retire by 2030.

That’s the same amount that PJM expects its load to grow over the next 15 years, with the grid operator’s peak load forecast having increased by over 3 GW for 2025-26. Energy use in the PJM region is projected to increase 40% by 2039 — from 800,000 GWh to about 1 million GWh — driven by increasing electrification coupled with the meteoric rise of data centers and AI.

Load growth and retirement of large fossil generation could have been mitigated with greater buildout of renewable energy resources. But that’s been slowed by challenges including a major interconnection backlog that’s limited new generation capacity. While this backlog is a problem across the U.S., it’s most acute in PJM, which got the lowest score of all grid operators on Advanced Energy United’s 2024 Generator Interconnection Scorecard. As of early 2024, PJM had over 3,000 projects, representing 286.7 GW of capacity, in its queue. What’s more, the average time for a project to get approval has increased significantly in recent years to more than 5 years. Whether the issues begin with the interconnection queue or emerge after it, one thing is clear: energy supply is not keeping pace with demand, which doesn’t bode well for energy affordability or energy reliability — and slows down our quest for a net zero grid.

A flexible, cost-effective solution

The good news is that we have solutions that are ready to deploy now — and that will benefit grid operators, utilities, and customers alike.

One key to unlocking supply is distributed energy resources (DERs), including solar and energy storage. DERs mostly avoid interconnection queue issues because they are not interconnected at the transmission level. They can be deployed much more quickly and cost-effectively than large power plants. While we need to bring considerable amounts of new renewable energy generation online, utility-scale deployments alone aren’t a panacea. Most projects in the PJM queue are not expected to come online before 2030; the timeframe will be much longer for projects yet to enter the queue. So, the problem is not the market sending the signals to build — it’s getting the approvals to build.

DERs can avoid these delays. But as powerful as DERs can be for surmounting PJM’s supply and demand challenges, they can’t do all the work on their own. DERs like solar and wind introduce their own challenges, such as generation intermittency and grid imbalances. While energy storage can significantly mitigate these challenges, it can’t completely surmount them without any intelligence driving dispatch.

An even more effective solution, in concert with deploying DERs, is coupling distributed energy storage with an energy management system (EMS). To be the most effective, an EMS should be powered by predictive control and real-time optimization software that enhances energy storage performance for optimum peak shaving, load management, and coincident peak reduction.

• Peak shaving and load management: Installed behind the meter along with energy storage, an intelligent EMS can help maintain system reliability. Using load forecasting, it can reduce peak loads for commercial and industrial clients and reduce large loads on the distribution system. Large commercial and industrial customers benefit by reducing their demand charges, while distribution system operators benefit from peak management of large industrial loads.
• Coincident peak reduction: Installed in multi-site configuration, value stacking site peak loads and system coincident peaks can bring C&I customer savings while adding coincident peak reduction for distribution system operators (DSOs). When combined with an intelligent EMS, DSOs can automate coincident peak shaving solution and monitor effectiveness at the distribution feeder.

Even more powerful is aggregating these DERs + EMS + energy storage deployments into virtual power plants (VPPs), which are proving their worth as key players in increasing grid capacity and balancing the grid.

As their name implies, VPPs can take the place of power plants, enabling much-needed energy capacity to be deployed more quickly and cost-effectively. According to research firm Wood Mackenzie, the VPPs that are planned or already deployed in the U.S will offset 33 nuclear reactors’ worth of power.

They’re also showing they can provide valuable grid services. Under the U.S. Department of Energy (DOE) as part of the $1 billion Puerto Rico Energy Resilience Fund (PR-ERF), Generac Power Systems will facilitate residential solar and battery energy storage for Puerto Rican households. When aggregated into a VPP, these will provide resilience for the region’s entire power system. VPPs have already supported California’s power grid during a July heat wave. In Texas, grid operator ERCOT has enrolled 7 MW of flexible demand in VPP programs, to avoid a repeat of the Winter Storm Uri outages.

Demand response, a key component of VPPs, has kept the lights on this summer during California and Texas heat waves. PJM values demand response enough to have included it in the capacity it procured for 2025-26, but at only 5% of that capacity. Adding demand response in the form of automated VPPs can ensure reliable electricity supply in Texas and other regions.

The time to act is now

Our nation’s energy supply is facing a crisis. This issue is flaring up in PJM, where prices could remain high; Morgan Stanley projects prices could jump 157% in the next capacity auction in December, to a cap of $695MW/day. But no region is immune. Every region stands to benefit by deploying more VPPs with intelligent EMS capabilities — with more reliable energy and lower costs.

California could avoid $755 million in traditional power system costs and save consumers $550 million annually by deploying about 7.7 GW of VPP capacity — five times the state’s current capacity — by 2035, according to a report from Brattle.

The U.S. Department of Energy determined that tripling VPP deployments in the U.S. could address 10-20% of the expected 200 GW of peak-coincident demand that must be served with new energy generation resources by 2030 — while avoiding about $10 billion annually in grid costs. Along with other advanced technologies, VPPs could help expand the nation’s grid capacity by 20–100 GW — at a quarter of the cost of transmission lines.

The urgency of the situation requires that we act now. We have the tools; now, we need to use them.

Matt Irvin is CEO and co-founder of Maplewell Energy. Irvin co-created the company’s optimization and predictive control technology to enhance peak shaving applications, load management, and coincident peak. He has spent his career serving utilities, with experience at General Electric and Stanley Consultants. Matt has been lead architect on deep learning forecasting models, cloud software architecture, and edge computing architecture and has helped countless solar developers, ESCOs, energy managers, and facilities managers value stack revenue streams on battery energy storage.

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In a new weekly update for pv magazine, OPIS, a Dow Jones company, provides a quick look at the main price trends in the global PV industry.

Cell prices were assessed stable in the week to Tuesday as the Chinese market remained closed during September 15-17 for the Mid-Autumn festival. The FOB China Mono PERC M10 cell and TOPCon M10 cell prices were flat at $0.0354/W while the FOB China Mono PERC G12 cell prices were assessed unchanged at $0.0372/W week-to-week in the absence of trading activity.

Demand was sluggish with market participants sidelined by the holidays. The recent price declines in the cell segment, amid uncertainties about when this downward trend would stop, also dampened sentiment. M10 PERC cell prices fell by 21.68% since January this year, while M10 TOPCon cell prices fell by 39.4% over the same period to Tuesday, according to OPIS data.

A further reduction in cell prices would result in cell producers shutting production lines as current cell prices were below the costs of production. On the other hand, some market participants expect a slight increase in cell prices after the holidays as cell manufacturers have been mulling price hikes amid slight gains in the upstream wafer segment for the past few weeks.

In the domestic Chinese market, prices were stable. Mono PERC M10 and TOPCon M10 were assessed unchanged at CNY 0.290 ($0.041)/W, week-to-week while prices of Mono PERC G12 prices were flat at CNY 0.300/W from the previous week.

China exported about 4.65 GW of solar cells in July with the majority bound for India, an industry source said.

Outside of China, India’s Ministry of New and Renewable Energy (MNRE) is seeking feedback on draft guidelines for an Approved List of Models and Manufacturers (ALMM) specifically for solar cells, aiming for implementation on April 1, 2026, according to a memorandum issued September 7.

The memorandum stated that all projects under the purview of ALMM must source their photovoltaic modules from models and manufacturers included in the ALMM List-I for solar PV modules. These modules must, in turn, use solar PV cells from models and manufacturers in the ALMM List-II for solar PV cells.

U.S. trade officials on Friday locked in the new 50% Section 301 tariffs for cells, assembled into modules or not, out of China. Those will take effect on September 27. More interestingly, the USTR in the same notice proposed that the same tariff should apply to polysilicon and wafers out of China. This would push Chinese companies to rethink their supply chains entirely. The proposal on polysilicon and wafers will be subject to a public comment period, for which the details will be communicated separately.

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.

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Advances that increase operational efficiencies, reduce installation time and accelerate project completion will drive progress.

The Industrial Revolution is widely recognized as the 80-year period when the world transitioned from creating goods by hand to using machines. Although thought of by many as a manufacturing revolution, the era was in reality an “innovation revolution” where the most dramatic advancements helped to accelerate the production of goods, the construction of buildings and the development of new products.Similarly, in today’s race to meet U.S. solar energy goals, domestic manufacturing capacity is just one piece of the puzzle. According to the Solar Energy Industries Association (SEIA), U.S. solar panel manufacturing capacity increased 71% in the first quarter of 2024. In addition, more than 25,000 jobs and 47 new manufacturing projects have been added to the U.S. solar industry since 2022. Consider the recent explosive growth of solar manufacturing projects:* U.S-based SEG Solar opened a solar panel manufacturing plant in Houston in August 2024. * Waaree Energies recently announced plans to open a solar panel manufacturing facility in Texas. * California-based solar panel manufacturer Solar Plus also announced plans to open a new facility in Texas. * PV Hardware USA (PVH USA) opened a new, 50,000-square-foot, $30 million solar tracker manufacturing facility in Houston.

While impressive in its size and scope, this increase in manufacturing alone will not be sufficient to meet the current administration’s goal of reaching carbon-free electricity generation by 2035. If the United States is going to reach this ambitious goal, manufacturing capacity must be buoyed by innovations that help reduce the costs of and speed the construction of solar generating projects. For example, the new PVH USA facility in Houston introduced an in-house pre-assembly process that improves solar installation efficiency. This approach reduces the number of components delivered to a panel construction site by over 85%, resulting in a more than 40% reduction in installation time for solar projects.In February 2022, the U.S. Department of Energy (DOE) published “America’s Strategy to Secure the Supply Chain for a Robust Clean Energy Transition” resulting in the first comprehensive U.S. government plan to build an Energy Sector Industrial Base. Due to the recommendations from this report and ongoing policies supporting expansion of energy manufacturing, the renewable energy market has been greatly boosted – and in turn, so has the country’s energy security.But just as earlier advancements accelerated the progress of the Industrial Revolution, today’s innovations will be the key to meeting U.S. solar energy and climate goals. As the United States forges ahead with its ambitious clean energy agenda, there is no substitute for new ideas that decrease costs, increase efficiency and reduce the time required to bring solar projects to completion.Rodolfo Bitar is vice president of business development for PV Hardware USA (PVH USA).

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If we cut off a significant portion of our module supply, we risk again making a short-sighted policy decision that will erode the U.S. solar industry and slow our progress toward meeting our climate commitments.

I get it. I do. As stewards of U.S. taxpayer money, I understand the impulse behind a bipartisan group of senators’ introduction of the American Tax Dollars for American Solar Manufacturing Act.

Senators Jon Ossoff (D-GA), Sherrod Brown (D-OH), Bill Cassidy (R-LA) and Rick Scott (R-FL) introduced the bipartisan legislation to prevent “foreign entities of concern” companies from using American tax credits designed to accelerate American solar manufacturing. On the surface, it makes perfect sense. Why should U.S. taxpayers subsidize non-American companies in their quest to take advantage of the opportunities in the solar market in this country?

Here’s the rub: As with most legislation like this, it could have unintended consequences for the growth of the U.S. solar industry. As we look to stabilize the business side of the industry and energy costs for consumers, communities, municipalities, schools and businesses across the country, some of those consequences could do precisely the opposite of what its sponsors envision.

For example, the Solar Energy Industry Association (SEIA) announced in June that a record-setting 11 GW of new solar module manufacturing capacity came online in the United States during the first quarter. It was, according to SEIA, the largest quarter of solar manufacturing growth in American history—a massive increase of 71% in module manufacturing capacity.

This growth represents an enormous expansion since the passage of the Inflation Reduction Act (IRA) of 2022. I applaud all the efforts to expand solar manufacturing in the United States and support reshoring as much of the solar supply chain as possible. It’s crucial not only to the growth of the industry but to the economic imperative of safeguarding our energy supply from potential fluctuations shaped by world events out of our control. Without a secure, domestic solar supply chain, the industry will never be able to reach its full potential.

The problem facing most developers is that we still don’t have the manufacturing infrastructure to cut ourselves off entirely from Chinese module producers. Regrettably, the U.S. government has only recently recognized its potential to significantly contribute to the development of our solar module infrastructure. The decision by the U.S. Department of Energy (DOE) to award Qcells a $1.4 billion loan guarantee to build their all-inclusive factory system in Georgia reflects this changing attitude. However, most of the companies building U.S. factories are of Chinese origin, which is where the senators’ well-meaning legislation begins to falter.

While the companies building many of these factories are of Chinese origin, they are hiring real-world U.S. workers—and lots of them. Not only are they employing construction workers, electricians and other skilled tradespeople to build the factories, but they will also need U.S. workers to staff the factories once they are operational. Well-paying jobs stabilize communities and improve conditions for other workers in the area. In addition, the communities also benefit by increasing their tax base for schools and other public works.

Many communities where these factories are being built have missed job opportunities like these. To restrict these U.S.-based subsidiaries from building these factories and adding U.S. citizens to the payrolls would be an unintended instance of cutting off their noses to spite their faces.

Additionally, it will raise prices on modules significantly. According to Columbia University’s Center on Global Energy Policy, the costs of solar modules are already two to three times higher in the United States than in Europe. A recent study published in Nature estimates that cutting China out of supply chains increases solar module prices by 20 to 30% compared to a scenario with globalized supply chains. If prices rise too steeply, it could stall numerous ambitious solar projects in the pipeline and potentially force some developers out of business. That’s something the U.S. energy transition can’t afford.

China currently controls 80% of the polysilicon production, meaning we can’t remove China from our value chain. We simply don’t have the in-ground supplies of polysilicon that they do. Now, we can alleviate some of this reliance by using cadmium telluride modules, but we have to become comfortable with the idea of buying our raw materials from another country, the way we do with other consumer goods. Otherwise, the vital solar deployment in the United States is going to stall. Here’s what I mean:

Let’s say the proposed act becomes law, and we sharply reduce Chinese companies remaining in the U.S. market by restricting their access to IRA incentives as well as the ever-present tariffs on modules. Where does that leave us with U.S.-owned, U.S.-based module suppliers? Per the U.S. Department of Energy (USDOE) Solar Energy Technologies Office Solar Manufacturing Map, U.S.-based module production capacity is about 40 GW. Granted, this is a different number than what other organizations report, but it’s the U.S. DOE dataset I chose to use. Of that total, only 25 GW are produced by non-Chinese-owned companies. Strictly U.S.-owned, U.S.-based companies currently only produce about 11 GW.

The U.S. Energy Information Administration (EIA) projects the percentage of U.S. electric capacity additions from solar will grow from 46% in 2022 to 63% this year and 71% by next year. That means we will need about 66 GW of additional capacity by the end of next year. Since, again, according to U.S.DOE data, we only produce about 11 GW from U.S.-based, U.S.-owned companies, that means we will be 55 GW short of what we need if we limit ourselves to only U.S.-based, U.S.-owned companies. That’s going to significantly crimp our ability to deploy solar effectively in the United States.

I am all in favor of U.S.-owned, U.S.-based solar manufacturing, but who will bear the cost to get us there? The costs will come in many forms—fewer jobs for U.S. workers, higher electricity prices and slower solar development, just to name a few. The question before us is how to bridge the gap between our current capacity and where we need to go. Let’s lead by using the carrot of investing in U.S.-based, U.S.-owned companies instead of deploying a stick that reads, “No one else (well, just China as a foreign entity of concern, actually) is allowed into our market.”

The proposed law is simply another way to impose tariffs on Chinese companies without going through the formal tariff-imposing process. Like tariffs, the unintended consequences of this law will decrease overall solar deployment in the United States. In fact, it’s even worse than that: Not only will it constrict supply, but it will remove the incentive for foreign companies to invest heavily in the United States. Is it OK to tell the laborers, electricians, and other solar workers who are building arrays that their livelihoods must be put on hold because we simply don’t have the modules? I think not.

I feel for the senators in question. In a vacuum, where the economic imperative wasn’t so central to re-building an industry virtually from scratch, I might even be willing to meet them halfway. Unfortunately, we are all in the process of unwinding short-sighted U.S. policy from decades ago that allowed almost all solar production capacity to go off-shore (it’s often easy to forget, but the United States invented solar cells). This great unwinding means we need to focus on a “yes, and” approach.

Yes, we currently need more modules than U.S. producers can make and yes, the IRA is working well as we see additional U.S.-based investments by U.S. companies like First Solar. The IRA incentives are working, and replacement capacity investment is on the way. If we cut off a significant portion of our module supply, we risk again making a short-sighted policy decision that will erode the U.S. solar industry and slow our progress toward meeting our climate commitments. Let’s not have to rebuild our industry again.

Scott Buckley is president of Green Lantern Solar, a company that since 2011 has advanced the development, construction and operation of more than 125 community solar projects and commercial solar solutions for municipal, education, healthcare and government entities. Green Lantern works with landowners to revitalize and re-develop low-value sites such as brownfields, landfills, quarries/pits/extraction sites and other challenging real estate.

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The second in a two-part series that looks at load growth as a result of the increasing electrical load growth by data centers and considers how low-income customers are protected.

Part 1 of this blog looked at legislative and utility actions that address the potential grid and energy impacts of data centers, including the future downstream cost issues associated with a utility’s response to the massive amount of incoming load growth and the capital recovery that customers, especially those that are low-income, will have to deal with.

Many additional state and utility programs exist and vary in terms of approach and scope and can take the form of an income-based discount, a percentage of income payment plan (PIPP), and an income-graduated fixed charge, among other types of payment assistance, like late payment fee and utility shut-off exemptions.

To determine which approach best serves low-income communities and can garner the most support from utilities for future implementation, several state utility regulators have recently been on the case to do just that. Two such investigations began earlier this year in the competitive utility markets of Maine and Massachusetts.

The Public Utilities Commission in Maine finished its inquiry into affordable ratemaking opportunities towards the end of May this year, reporting that adopting a price cap on what utilities can charge to a low-income customer participating in an assistance program is problematic, as the compliance measures needed for such an approach could be administratively burdensome for utilities and could place them into a role of enforcement, a role the Commission did not feel would be appropriate. The Commission felt that a low-income price cap would incentivize utilities to no longer enter into contracts with low-income customers due to the hassle associated with their participation and the fluctuating income of certain customers, making eligibility determination challenging to keep up with. The Commission instead recommended that a competitive electric provider should obtain express, written authorization from customers before renewing a service contract and provide a price comparison between the provider price and the state’s standard offer.

Map depicting the various low-income household electric rate discount programs that state and/or electric investor-owned utilities offer as of June 2024. The map does not include LIHEAP, medical-based discounts, late fee exemptions, “pay-later” programs, shutoff exemptions, or charitable assistance programs. Source: Justin Lindemann, NC Clean Energy Technology Center.

In Massachusetts, state regulators have been investigating different low-income ratemaking options, and utilities provided their two cents on what they felt outweighed the implementation costs. Since utilities in the state are already required to provide a percentage discount to rates for certain low-income customers, National Grid, Eversource, and Unitil commented that a tiered discount rate would be the best option over PIPPs. They referenced Liberty, Eversource, and Until in New Hampshire as a model due to their existing five-tiered discount rates. Utilities supported the tiered discount approach because it allows for flexibility and lower compliance costs and removes “cliffs,” in which small income changes might result in a household losing assistance. Due to the broad income ranges and multiple tiers usually offered under a tiered discount program, the prevalence of “cliffs” would be minimized. As for PIPPs, the utilities mentioned that customers might have data privacy concerns due to the procedures required to determine one’s income eligibility. Compared to a tiered discount, the utility only needs to know the specific tier range the customer falls into. The investigation has been taking place as state regulators also examined Unitil’s proposal to increase its low-income discount rate to 40%, which was approved in late June.

Reflected by the Northeastern utilities, support for a discount-based approach is highly favored, and most investor-owned utilities in the country, albeit some with limited coverage, are already using this approach. PIPPs, on the other hand, garnered less support, which, if the utility perspective is any indication, may explain why they have only been administered in just five states and mostly through statewide regulations.

Circling back to the central issue, due to the influx and expansion of new data centers and the projected load to come with it, utility customers are expected to anticipate further electric rate increases, and approaches like those mentioned above would likely provide critical assistance. Examining the data center markets in the country with the largest growth and the kinds of low-income utility bill assistance that such states and their investor-owned utilities currently provide may grant an understanding of what still needs to be done to shield low-income customers in response to the projected market expansion.

The following states are projected to have the most data center growth in the country by 2030, according to EPRI, each providing bill assistance through different approaches:

1. Virginia

   • The state enacted a PIPP via legislation in 2020, directing only Dominion Energy and Appalachian Power to collect a universal service fee. The fee funds the PIPP and its eligible participants, who must apply for eligibility through the Department of Social Services, after which the utility enrolls a customer’s account. Under Dominion, customers who utilize electric heat will have their monthly bill capped at 10% of their income. At a minimum, customers will pay $10.
   • Virginia’s projected data center electricity consumption may grow to 46% of the state’s total by 2030, compared to about 25.6% in 2023.

   • Texas

   • Texas offers limited financial assistance outside the state’s LIHEAP program. El Paso Electric Company, situated in the eastern tip of the state, offers a low-income discount that exempts eligible customers from paying the customer charge.

   • Texas’ projected data center electricity consumption may grow to about 10.6% of the state’s total by 2030, compared to about 4.6% in 2023.

   • California

   • Utilities in the state must offer various income-based discounts under either the California Alternative Rates for Energy (CARE) or Family Electric Rate Assistance (FERA) programs. Customers eligible for the CARE program may receive a 30% to 35% electric bill discount through the utility. Families whose household income exceeds those allowed under the CARE program can receive an 18% discount on their electric bill through the FERA program.

   • Pacific Gas & Electric (PG&E) also operates a PIPP pilot program until 2027 for a limited number of customers, capping the monthly electric bill at $32 for certain income-eligible customers. Those who do not qualify under the program’s income guidelines may still qualify for a $97 cap.
   • California is also the only state in the country that has implemented an income-graduated fixed charge. State regulators approved a fixed $6 charge for CARE customers and $12.08 for FERA households. The new structure also decreases the residential energy usage rate by $0.05 to $0.07 per kWh. Though the rate structure has been approved, large investor-owned utilities have been given more than a year to transition, with the latest implementation date being March 2026 for Pacific Gas & Electric – the largest utility in the state. However, around the same time the fixed charges were approved, state legislators introduced a bill to repeal the original bill that authorized the income-graduated fixed charge. The bill replaces the equitable rate structure with a $10 cap.
   • California’s projected data center electricity consumption may grow to 8.7% of the state’s total by 2030, compared to 3.7% in 2023.

   • Illinois

   • Illinois’ Department of Commerce and Economic Opportunity administers a PIPP for customers with an income of up to 150% of the federal poverty guideline. The payment plan caps a customer’s bill at 6% of their income, as available to a limited number of utilities, including Ameren Illinois and ComEd. The program is funded by a meter charge for other low-income assistance programs and a one-time utility contribution. The availability of program funds has been an issue, as applications have been closed since October 2023 and continue into mid-August this year.

   • Illinois’ projected data center electricity consumption may grow to about 12.6% of the state’s total by 2030, compared to about 5.5% in 2023.

   • Oregon

   • Oregon’s electric investor-owned utilities offer varying low-income discounts. Pacific Power uses the state median income (SMI) to establish a tiered discount structure that gives customers up to 20% of SMI a 40% discount. In comparison, those with an SMI above 20% and up to 60% receive a 20% discount on their electricity bill. Certain customers living in a multifamily residential building may receive a 30% discount.

   • Portland General Electric offers a similar discount designed to follow the SMI and established five tiers for those with an SMI of up to 60%. The highest discount a customer may receive is 60% for having an income up to 5% of the SMI.
   • Oregon’s projected data center electricity consumption may grow to about 24.1% of the state’s total by 2030, compared to about 11.4% in 2023.

Looking forward

Knowing now what the fastest-rising data center markets already offer as assistance to low-income customers, it is apparent that there is a baseline of support that many customers can take advantage of. With each state offering LIHEAP payments and most utilities offering some discount to income-eligible customers, only a few provide customers with something other than a discount, going as far as capping residential rate payments altogether. Considering the significant shares of electricity consumption from data centers that each state is expected to be impacted by utilities in these states will surely propose significant capital investment reimbursements from their customers to combat the demand by the end of the decade. Millions of low-income utility customers are thus expected to be at an even greater risk of financial distress than today, and with LIHEAP facing current – and perhaps future – budgetary constraints, building out state and utility assistance has become all the more important.

In recent years, some states and utilities have implemented certain mechanisms that go beyond a simple discount, from California’s income-graduated fixed charge approach to Virginia’s PIPP program. Still, many have not equipped low-income customers with the certainty that they can withstand the weight of future bill increases, let alone the current rates. Customers may benefit from a definitive price cap or lower rates based on income, perhaps even instituting cost recovery exemptions that disallow certain customer classes from having to subsidize the cost of new resources needed to combat the energy demand from load sources that a specific class is not using or benefitting from, like data centers, among other alternatives. With the possible spike in energy burden rates across the country, building more equitable pathways to accessing rooftop or community solar may also be the key as low-income customers seek energy independence and savings. In addition, increased home energy efficiency, made possible by federal, state, and utility energy efficiency incentives explicitly designed for low-income communities, could be part of the solution as well.

All in all, as utilities plan to respond to the incoming flood of data center load by constructing additional generation resources, recovering a significant amount of capital from their customer base, one question to ask is: Will low-income customers be provided with enough protection?

Justin Lindemann is a policy analyst at NC Clean Energy Technology Center.

This is the second in a series originally published by NC Clean Energy Technology Center. Click here to learn about our DSIRE Insight subscriptions, custom research, and consulting offerings on various clean energy technologies for interested individuals or organizations. Read Part 1 here.

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Although many states and utilities offer low-income assistance programs, what are the states with the most considerable data center growth already doing, and are they prepared for what’s to come?

By the decade’s end, data centers in the United States are projected to account for as much as 35 GW of demand and about 9% of the country’s electricity consumption. Though these are merely forecasts, to power the 24/7, 365-day operations, utilities plan to finance dozens of GWs worth of new generation resources from clean energy to natural gas.

According to a Goldman Sachs study, natural gas could supply 60% of the expected data center demand. This significant increase in gas is reflected in many utility integrated resource plans, including Dominion Energy in Virginia, which wants to build more than 2.9 GW of new long-term gas capacity in the next 15 years as a short-term solution to load increase. Some utilities have also resorted to proposing new payment structures in addition to planned generation resources. AEP Ohio proposed a unique tariff structure that, if approved, would require new large-capacity data centers to pay for their own transmission needs, and Duke Energy is considering contract agreements for data centers that would require them to provide upfront financial contributions to construct new generation resources to help power them.

Besides natural gas, nuclear is also seen as an option to power data centers, with various developers and data companies already examining this alternative. For example, Oklo, a California-based advanced nuclear company, has committed itself to providing its clean energy solution in response to increasing demand for AI adoption and data centers. The company announced a non-binding partnership in late May with Wyoming Hyperscale, which wants to use Oklo’s microreactor design to power a state-of-the-art data center campus using 100 MW of nuclear energy. As for data-heavy companies, Amazon Web Services bought a 960 MW Cumulus data center campus in northeast Pennsylvania in early March that will be powered by the 2.5 GW Susquehanna nuclear power plant. Nevertheless, with the construction price for compatible small modular reactors (SMRs) rising and SMRs and microreactors still far from commercialization, this reality may not come to fruition anytime soon. Plus, if new large-scale reactors are considered, the estimated $7.6 billion cost to ratepayers of the now-operational Vogtle Units 3 and 4 – which increased residential rates by about $9 a month – might dampen the prospects of nuclear as an option as well.

Either way, new resource proposals will persist as artificial intelligence and other significant data sources enter the equation as a catalyst, partly because heavy-data users like Google are experimenting with technology like AI-infused internet browsing. For context, compared to a Google search that consumes approximately 0.3 Wh per request, a single AI-powered Google search request may even consume about 23x to 30x more than, according to worst-case scenarios and research estimates published in late 2023. It is important to note that these estimations are dependent on a number of factors staying the same, including the availability of AI-based chips and the 24/7 operations of data centers at max capacity. However, as data center efficiency grows and operation procedures change, these estimates will shift.

Moreover, while the national impact of data centers is expected to take up a significant chunk of the nation’s overall electricity consumption, the most significant ramifications will be seen on a state-to-local level, especially as growth continues to concentrate in specific pockets of the country. State by state, Virginia is far ahead in the number of current data centers. The northern part of the state is considered the nation’s most significant data center market, even the world, with 35% of the globe’s hyperscale data center share – a type of data center facility that typically supports the business activities of massive data-driven companies like Google, Amazon, Meta, and Microsoft, just to name a few. The state legislature has responded by introducing bills this year to limit the provision of sales and use tax exemptions to only centers that demonstrate certain energy efficiency requirements, requiring localities to assess the grid impacts of proposed center sites, and disallowing utilities from recovering costs through their customers from electric grid infrastructure that mainly services the load coming from data centers.

Other state responses have been more mixed in their reaction, with Massachusetts – a state with about 50 data centers – introducing legislation courting new centers with a sales and use tax exemption, Michigan pushing forward with an extension of their existing data center tax exemption until mid-century, and New York – with almost 130 data centers – wanting to create an energy benchmarking program to account for high-energy infrastructure.

While the legislative and utility actions mentioned address the potential grid and energy impacts of data centers, they also touch on the future downstream cost issues associated with a utility’s response to the massive amount of incoming load growth and the capital recovery that customers, especially those that are low-income, will have to deal with.

Map of energy consumption from data centers in states with significant 2023 load. Data center consumption data depicts the highest-growth scenario states are projected to see in 2030 relative to total electricity consumption. Data Source: EPRI

Low-income load bearers

As utilities attack the projected data center load growth issue with additional investments and emerging technological applications, the customer is positioned to help subsidize the cost through rate increases as part of these utilities’ cost recovery processes. In the case of Duke Energy in North Carolina, the utility can recoup about 10% from new construction.

However, while wealthier households have the financial cushion to protect themselves from these rate increases, low-income customers do not, so the weight of frequent or significant bill increases bears greater financial struggle. The lack of financial security for low-income households is exemplified by one’s energy burden. In the United States, the national average energy burden, or the percentage of gross household income spent on energy bills, for low-income households is 6%, according to the Department of Energy’s Low-Income Energy Affordability Data (LEAD) tool. This average is based on an estimated 51 million households that identify as low-income, which is about 42% of all households in the country.

Depending on a person’s locality and household income, the energy burden can even be higher than 30%, particularly if you live in the Southeast. Even the financial toll from trying to keep cool during the summer heat can spike a household’s energy burden, which the National Energy Assistance Directors Association (NEADA) and the Center for Energy Poverty and Climate (CEPC) reported will increase by 7.9% this year. With the expected increase in utility bills in the coming years, such a high and localized energy burden rate may become more widespread and prevalent.

Low-income utility bill assistance

Since the reality of the energy burden in the country is not a new phenomenon, there are a number of financial assistance programs and approaches that the federal government, states, and investor-owned electric utilities have either implemented or are currently examining as options. For example, modeled after Maine’s “Project Fuel” program and created in response to the OPEC oil embargo in the early 1970s, the federal government established the Emergency Energy Conservation Program later in the decade to provide weatherization-focused assistance and eventually direct bill assistance for low-income households. It was one of the earliest programs of its kind. It would end up turning into what is now known as the Low Income Home Energy Assistance Program (LIHEAP), operating in every state, the District of Columbia, and most tribes and territories, to prevent energy-bill payment emergencies by providing payments to fuel suppliers/utilities and/or households.

Map depicting the national energy burden distribution for low-income households based on state median income; Source: U.S. Department of Energy Low-income Energy Affordability Data Tool

LIHEAP is commonly used to determine income eligibility for several other state and utility assistance programs. However, access to the federal program has been severely limited. Federal funding for fiscal year 2024 was cut by $2 billion compared to 2023, reducing the number of low-income households served by 1 million in addition to the program’s benefits. Because of the severe budget fluctuations that each state program faces due to federal decision-making, state and utility assistance programs are critical to help fill in the gap and then some.

Many additional state and utility programs exist and vary in terms of approach and scope and can take the form of an income-based discount, a percentage of income payment plan (PIPP), and an income-graduated fixed charge, among other types of payment assistance, like late payment fee and utility shut-off exemptions. Income-based discounts entail a utility or a state providing a continuous or one-time payment attributed to an income-eligible customer, either removing the mandatory fixed charge from a bill or providing a percentage reduction of the overall monthly bill according to a specific income range, among other offers.

Then, there are PIPPs, which refer to income-specific payment plans that allow certain customers to pay only a portion of their utility bill based on a percentage of their overall income. Existing PIPPs vary in terms of their price cap. Still, no program in the country inches above 10% of a household’s income, and some programs may also determine percentage payments based on the primary heat source, electric or otherwise. This payment plan is comparable to a student loan income-driven repayment plan. It can be a helpful tool to limit a low-income household’s monthly energy expenditures and allow households to dedicate a higher share of their disposable income to pay off other bills and to put food on the table, or perhaps allow a household to establish and/or grow their savings.

There is also the income-graduated fixed charge approach, which has only recently been implemented in California. This novel method of equitable ratemaking mirrors progressive taxation, in which the lower your income, the less you must pay, and is a significant departure for investor-owned utilities in the state impacted by this change, which did not impose fixed charges before this.

Part Two of this blog will look at the utility perspective on equitable ratemaking.

Justin Lindemann is a policy analyst at NC Clean Energy Technology Center.

This article originally published by NC Clean Energy Technology Center. Click here to learn about our DSIRE Insight subscriptions, custom research, and consulting offerings on various clean energy technologies for interested individuals or organizations.

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With the introduction of the American Tax Dollars for American Solar Manufacturing Act earlier this month, senators are trying to close this work-around and put American manufacturing back on a level playing field.

Two years ago, the Biden Administration and Congress worked together to begin the process of reshoring solar manufacturing.

For the last 20 years, China has been working hard to secure a monopoly over this critical technology. While China has mostly succeeded, the Inflation Reduction Act (IRA) created a set of incentives to get us back in the game. But, one critical piece may undermine our progress – we are letting China-headquartered companies locate final manufacturing in the United States, taking advantage of those same incentives while preserving their supply chain monopoly over the fundamental components.

Fortunately, with the introduction of the American Tax Dollars for American Solar Manufacturing Act earlier this month, senators are trying to close this work-around and put American manufacturing back on a level playing field.

Solar energy was invented in the United States, but right now nearly all of it, and about 99% of the fundamental component (the wafer), is being manufactured elsewhere, specifically, by Chinese-controlled companies. As our government works to invest in clean energy, we’re incentivizing companies to build back their operations in the U.S. so Americans can benefit from good-paying jobs, foster innovation from our world-leading R&D abilities, and establish energy independence in the critical technologies for our future.

Congress created a remarkably far-sighted system to reshore solar, batteries and wind technology. Policymakers not only created supply-side incentives in the advanced manufacturing production incentive that encourage manufacturers to build big factories quickly, but they paired them with demand-side incentives to give developers who use the products a bonus if they buy the products of those factories as they build solar and wind farms.

Unfortunately, the guidance for that bonus issued by the Treasury Department so far has missed the mark and has now become one of the biggest obstacles to jumpstarting the onshoring of American solar manufacturing. As it stands, Chinese companies can continue to leverage their monopoly power over the fundamental components of solar, produced with weak environmental and labor protections as well as massive direct subsidies, and sell to projects claiming the “domestic content bonus.” The clock is ticking to get this right as billions of investment dollars and thousands of jobs in solar manufacturing hang in the balance. In a very real sense, the future of solar energy depends on it.

China has dominated the solar manufacturing sector for a decade, and they’ve done it using a familiar playbook to those of us who’ve watched what the OPEC cartel has done to oil markets. OPEC’s ability to control price was legendary and it wasn’t limited to keeping prices high. Much more importantly, they could crash prices when they wanted to in order to run out competition. From “heavy oil” in Venezuela, to oil sands in Canada, to fracking in the US, OPEC has demonstrated again and again that you can either join them like Venezuela or be run over, with the attendant economic crash that people in Colorado, New Mexico, and Texas have seen many times over.

Now, China is doing the same thing in solar – as we are currently seeing the lowest prices in history, far below production cost – to stifle our manufacturing renaissance before it gets a chance to take off. Stymying competition and, thus, innovation is chapter one of the cartel playbook and China has perfected their execution.

Look no further than our friends across the pond: nearly all of the European solar manufacturers have closed operations due to insufficient protections from below market Chinese products. Many are even looking to the United States, but that will quickly change if our policies don’t keep pace.

To build a robust solar supply chain in the United States, our government must prove that we have the backs of our manufacturers. Companies will not invest here if they do not think they will be protected. How are U.S. manufacturers supposed to compete when China is setting prices far below the cost of production?

The fact is, international competition is not for the faint of heart. Our companies can hold their own, but only if the government has their backs and helps build the foundation for successful competition. This means leveraging our strengths; our unmatched innovation apparatus, strong investor base, and our brutally efficient market that forces constant improvement. But this only works if we don’t ignore the fact that China simply doesn’t have a free market economy.

Join our pv magazine USA Week to delve into the intricacies of and opportunities in the U.S. solar industry.Unlike the U.S., where most of our economy is us selling products and services to each other, their entire economic system requires exports, because their consumer class doesn’t have the ability to support their economy. This means, the U.S. government must work to produce a level playing field for U.S. manufacturers through the three legged stool of production support, demand incentives, and tariffs and other trade remedies. For the first time in several generations, we’re on the path to building the supports our economy needs to thrive in these all-important industries – as long as we don’t lose our will to succeed,

No one action can unwind the years of investment that Chinese-headquartered solar firms have made to control the solar industry, but we must act now with every tool at our disposal. By updating the domestic content bonus, enforcing smart trade policy, and standing up to the Chinese-controlled monopoly trying to protect their dominance by doing the minimum possible in the U.S. we can reshore the domestic solar supply chain, ensure the United States is clean energy independent, and secure a future for solar manufacturing in America that will benefit workers, businesses and the environment.

Mike Carr is the executive director of the SEMA Coalition. Prior to joining SEMA, Carr served as the principal deputy assistant secretary for the Office of Energy Efficiency and Renewable Energy and the senior advisor to the director of energy policy and systems analysis at the U.S. Department of Energy from 2012 to 2015. Prior to serving the President at DOE, Mike served as Senior Counsel to the Senate Committee on Energy and Natural Resources from 2004 to June 2012. He holds a law degree, with a Certificate of Specialization in Environmental and Natural Resources Law, from Lewis and Clark College and a Bachelor’s from the University of Colorado – Boulder.

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In a new weekly update for pv magazine, OPIS, a Dow Jones company, provides a quick look at the main price trends in the global PV industry.

From pv magazine Global

In the Chinese market, the majority of module sellers OPIS surveyed said the TOPCon FOB China market was quiet and prices were stable although there were some buyers out in the market talking down prices. Market talks of TOPCon prices below $0.09/W FOB China were circulating in the market, with one buyer pointing out that there were offers of Grade A TOPCon cargoes with a power output of 580-585 W of cargo sizes above 10 MW being offered at $0.081-0.086/W. However, sellers OPIS surveyed said there were no transactions at this level.

Most market discussions continued to be heard at $0.095-0.10/W FOB China. The Chinese Module Marker (CMM), the OPIS benchmark assessment for TOPCon modules from China was assessed at $0.096/W unchanged from the previous week while Mono PERC module prices were assessed stable week-to-week at $0.090/W.

Bearish sentiment prevailed in the Chinese domestic market as recent large-scale public tenders such as China Coal Group’s 4 GW procurement tender had attracted low offers of CNY0.7134 ($0.100)/W for N-type modules and CNY 0.7104/W for P-type modules with many market participants expecting module prices to fall to CNY0.70/W levels in the coming weeks, an industry source said. Mono PERC module prices were assessed at CNY0.777/W, stable from the previous week while TOPCon module prices were assessed unchanged at CNY0.801/W week-to-week.

In the European market, OPIS assessed the TOPCon modules delivered into Europe lower on the week at €0.109 ($0.12)/W, with indications ranging from €0.100/W to €0.120/W While delivered prices have eased in recent weeks due to a seasonal lull, a market source noted that August freight rates are still hovering at high levels compared to the previous few months.

According to OPIS records, August freight rates from China to Rotterdam are around $7000 to $8000 per forty-foot equivalent unit (FEU), approximately $0.0189/W to $0.0192/W, which is 30% higher compared to June. According to a European trade source, TOPCon modules up to Q2 2025 delivery were heard to be around €0.100/W to €0.110/W depending on the project size.

In the U.S. market, spot prices for U.S. delivered duty-paid (DDP) TOPCon modules fell this week to $0.291/W, with indications from $0.260/W to $0.320/W, while prices for Q1 2025 delivery averaged $0.311/W, ranging between $0.280/W and $0.350/W. OPIS assessed the U.S. mono PERC Q4 delivery module prices at $0.249/W, with indications between $0.200/W to $0.295/W, while 2025 delivery cargoes were around $0.27-0.34/W.

A major U.S. buyer said that prices of TOPCon modules from India and Southeast Asia scheduled for shipment this year have dropped recently. Another North American source noted growing concern among developers as autumn nears, particularly regarding the heightened tariff risk from Southeast Asia. Trade officials significantly broadened the scope of AD/CVD investigations this spring, increasing the likelihood of finding anti-market behavior in the four targeted countries. The White House has yet to clarify whether there will be tech exemptions or grace periods.

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Software can boost production and mitigate risks

Tracker monitoring software technology is an often overlooked but crucial element of solar development. New project discussions tend to focus on hardware components such as foundations and mechanical properties, but software capabilities are equally important. Inadequate technology can leave a site vulnerable to risks like weather damage and revenue loss.

Since tracker software is the underlying intelligence that optimizes all facets of a tracker’s performance and maximizes the likelihood of a site reaching its energy goals, it’s the “brains” behind the operation. Integrating the right monitoring software in the beginning can provide important benefits over the entire lifecycle of a project.

The ABCs of tracker technology

A tracker technology system consists of on-site hardware connected to compatible software. If tracker technology is lacking in the basics (i.e., the ABCs,) it can lead to lower site production and make O&M responsibilities more difficult.

On-site, a coordinated and well-engineered system will include:

• A network controller: The network controller, also called the tracker control unit, is a central hub that connects to row boxes and weather stations for the purpose of collecting data on site and sending that data to the cloud. Network controllers should connect to Supervisory Control and Data Acquisition systems (SCADA).
• Row boxes: Row boxes securely communicate tracking angle status and other variables continuously to the on-site network controller. When assessing a system, ask for what type of data output is received from the row boxes to determine how much a system communicates, and how easy it will be to remotely monitor and diagnose.
• Weather stations: Weather stations equipped with an anemometer, an ambient temperature sensor, and a snow sensor can gather details about on-site weather conditions such as wind speed and snowfall in real time. The stations feed the data to the network controller which in turn sends it to the cloud. A technology partner should be able to recommend a customized number of weather stations based on a site’s size and unique topography.

From there, tracker monitoring software should integrate seamlessly with the tracker hardware, and include an intuitive, easy-to-use dashboard.

The three Ps of tracker software technology

Tracker software benefits fall into three categories – protect, predict, and produce.

1- Protect from weather damage

Tracking technology can enhance a site owner’s ability to prevent weather damage and anticipate changes in weather conditions.

• Prevention: Wind damage is one of the most prevalent challenges that trackers face, and hail is becoming an increasingly significant concern in the solar community. Weather risks are compounded in areas prone to snow and flooding. It is essential that a tracker monitoring system includes the appropriate onsite sensors to safeguard solar assets. Sensors measure ambient temperature, wind activity, and depth of snow or flooding. This information enables timely responses to minimize production loss or damage.
• Forecasting: Forecasting is another critical feature of tracker monitoring. While weather patterns can change rapidly and hail is notoriously hard to predict, features like API integration with AccuWeather help site managers anticipate and proactively respond to changes, such as safely stowing trackers before a storm hits.Storing this weather data in the cloud provides ongoing, valuable insights for future planning.

2- Predict and ease O&M

Tracker monitoring software allows O&M to stay one step ahead of any situation and respond accordingly. Imagine being able to instantly detect when a row is not tracking on its normal path versus days or weeks of production losses due to maintenance issues. Look for predictive features such as:

• Real-time alerts via email or text that notify you of issues or changes
• An in-depth and user friendly dashboard that allows you to see inside the site, view real-time data, and access historical data
• Automatic stow position adjustment when sensors recognize certain thresholds, circumventing potential damage from wind, hail, or snow
• Machine learning capabilities that identify issues such as rows not tracking properly so they can be fixed before they impact performance
• Remote access that allows troubleshooting without going on site
• Zone controls that make it easy to perform routine maintenance like mowing while the rest of the site continues tracking

3- Produce more energy

Tracker software can maximize energy production by improving power output and minimizing downtime and/or damage. A sophisticated system will allow adjustments based on time of day, topography, and angle:

• Backtracking algorithms that minimize row-to-row shading by adjusting to the time of day (.i.e., morning or evening when the sun is low in the sky) prevent shadows from reducing output.
• With perfectly flat sites and level terrain being a thing of the past, tracker software needs to be able to adapt to topography nuances that cause trackers to be higher or lower than its neighbors. Systems that recognize the impact of shading based on topography, and can respond with solutions, add significant value and production gains.

Five questions to ask

Before making a final commitment, ask these five questions to get the clearest picture of a technology partner’s capabilities regarding its tracker monitoring software:

1. Who owns the technology for the trackers? Is it proprietary, or outsourced? Do you create both the software and hardware, or just one or the other?
2. Can the software be updated to include new features and improved functionality?
3. How accessible is the data? Is it stored in the cloud and easily available to the team?
4. Are there automatic features and integrated APIs that protect against weather damage – such as auto-stow based on sensor data? (Note that manual stow is a big red flag).
5. Does the software offer remote access for easy trouble-shooting, and an easy-to-use interface?

As sites age, the infrastructure ages as well, but software can be regularly updated, enhancing stakeholders’ abilities to protect against weather damage and optimize power production. With tracker monitoring software, owners and site managers are empowered to make decisions based on real-time data and historical details, and can rely on automatic adjustments designed to safeguard solar assets. Choosing tracker monitoring software technology wisely can yield immediate benefits, as well as benefits for years to come.

Ashton Vandemark is the founder and CEO of Sunfig, a part of Terrasmart since January of 2021, and maker of the Solar Instant Feasibility Tool (SIFT) design, performance and financial modeling platform.

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What it takes for low-income households to truly benefit from community solar.

A recent headline in this publication stated that “community solar increases energy equity.” It is true that incentives and legislation ensure that community solar projects are built to include low- to middle-income (LMI) communities in a meaningful way. And undoubtedly, the “middle income” part of “LMI” are benefitting from access to clean, low-cost solar power.

I do believe that the growth statistic referenced in the article – from two to 10% participation by LMI subscribers – is the result of a carrot and stick approach that has made it either a requirement or a bonus for community solar project developers to actively include traditionally underserved communities.

While this growth metric is significant, it may not be indicative of the reality for low–income households. When looking at the data, the question remains – how many of these LMI subscribers are actually middle income, rather than low income – the truly underserved?

Today, a host of frictions exist that make it really challenging to include low income households in a meaningful way. In fact, because of these frictions, it was surprising to read another statistic in the article; that the cost of acquiring LMI customers for community solar projects had declined by 30% between 2022 and 2023.

Our experience shows that engaging LMI households often requires significantly more handholding, which can translate to higher costs. This need for a higher touch isn’t surprising as these communities have historically been taken advantage of, so they approach a new service with great skepticism. Then, they often encounter a host of requirements that solidify this point of view, and make enrolling and keeping them as subscribers difficult.

Billing challenges

In many states, low-income households who enroll in community solar programs receive two bills: one from their community solar provider to pay for the community solar credits applied to their utility account; and one from their utility reflecting any remaining usage/bill spend not offset by the community solar credits. We’ve already introduced complexity – and from their perspective, the possibility of paying more – simply by introducing a second bill.

However, the issues do not stop there. Community solar credits applied to a bill in June might not be invoiced until August when the utility actually shares required data. Subscribers, understandably, can be confused since credits don’t reconcile with their most recent bill.

Some states, like New York, have instituted net crediting, a streamlined method for implementing community solar credits where savings are applied directly to the subscribers’ bill. In this scenario, a subscriber who receives a $100 community solar credit would realize the $20 (or 20%) savings on their primary utility bill. The $20 would simply be applied to the subscriber’s bill as savings and the $80 would be paid by the utility to the project owner. From the subscriber’s perspective, nothing changes and the savings are easy to see.

Unfortunately, net crediting is still the exception, not the norm. In New York, the New York State Energy Research and Development Authority (NYSERDA) have worked with community solar project managers like PowerMarket to advocate for approaches, like net crediting, that make the process easier for the LMI households who would most benefit from credits and discounts. States including Maryland, New Jersey, and Illinois are in the process of implementing net crediting. I am hopeful that more states follow suit.

Misguided consumer protections

In many cases, a number of states have had to react to bad actors in the retail supply and rooftop solar industries. These states have developed community solar programs with well-intended but inherently flawed consumer protection rules that have also created unnecessary roadblocks for subscribers. In llinois, for example, regulations require interested consumers to navigate a disjointed, digital-only enrollment process. For seniors who may not have an email address, or LMI households without reliable access to internet service, this creates friction from the start.

Illinois requires interested subscribers to first execute a unique, online-only Disclosure Form (DF). This DF creation process presents material barriers to households without computer access or technical savvy. In fact, if you are a subscriber who doesn’t have an email address, like many seniors, you need to sign an additional form representing as much.

In other states, including Massachusetts and Maine, the utilities, citing consumer protection and privacy, do not share critical subscriber usage and bill spend data with community solar managers, resulting in allocations that do not accurately match subscriber’s usage. In some cases, this translates into subscribers paying for credits that then expire. Or in other cases, consumers miss out on additional savings they could be enjoying if only their allocation could be increased. Without the data, however, community solar managers are simply relying on historical usage, and have no ability to adjust allocations as usage naturally fluctuates.

Reducing friction and increasing profitability

Community solar availability is absolutely increasing – not just for LMI households but for many other residential and corporate users. Tax incentives, regulatory requirements, and adders are certainly increasing access and usage.

However, real momentum will come when two things are addressed: reducing challenges for low income subscribers; and increasing profitability for developers.

The industry should unite in a call to action to regulators and legislators: reduce frictions that are hampering growth in equitable community solar access. A host of positive developments in different markets can serve as lessons-learned for the industry as a whole. There are states where regulators have instituted net crediting, enhanced data sharing between utilities and subscriber management organizations, and carved multiple avenues for humanely proving eligibility for LMI discounts. In these states, underserved households and individuals are finding it easier and more attractive to access the benefits of community solar.

Real change ultimately will be driven by looking at and learning from how community solar programs are administered in a creative and effective way. As these smart approaches to our industry proliferate nationally, we should begin to see real, explosive growth around community solar. Let’s work together to ensure that developers and underserved communities both benefit.

Jason Kaplan is president and general counsel at PowerMarket, a provider of acquisition, management, billing and support services to the solar energy industry. In his role, Kaplan works with a broad range of developers, municipalities, businesses and other stakeholders to make clean energy accessible to all.

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At the age of 92, President Carter's dedication to solar energy came full circle when his family decided to convert 10 acres of their peanut farm into a 1.3 MW solar farm.

In the late 1970s Jimmy Carter, a peanut farmer from Plains, Georgia, became the first American president to champion solar energy as a key to energy independence. His bold initiatives set the stage for the future of renewable energy in the United States.

At the age of 92, President Carter’s dedication to solar energy came full circle when his family decided to convert 10 acres of their peanut farm into a 1.3 MW solar farm. Florida-based J&B Solar was chosen to build this impressive array.

Jimmy and Rosalynn Carter with some of the J&B Solar project team members during construction in 2017. Image: J&B Solar

The story of this collaboration began on February 8th, 2017, when President Carter and his family attended the groundbreaking ceremony for the new solar project. Developed under a lease agreement with Atlanta-based SolAmerica, the project covered 10 acres and promised to produce over 55 million kWh of energy over the next 25 years. J&B Solar installed 200 concrete foundations, assembling aluminum racking, and positioning 3,852 polycrystalline solar panels. This setup was designed to generate more than half of the power needs for the residents of Plains, a small town with a population of 683.

Reflecting on this milestone, Carter, the soft-spoken 39th president, expressed his hope: “I hope that we’ll see a realization that one of the best ways to provide new jobs — good-paying and productive and innovative jobs — is through the search for renewable sources of energy.”

Carter’s presidency laid the groundwork for the solar industry. A former nuclear submarine officer with a background in science, he understood the potential of advanced technology. In 1977, amidst an energy crisis, he established the Solar Energy Research Institute (SERI) in Golden, Colorado, and set an ambitious goal to install solar energy in over two and a half million homes by 1985. He even installed solar panels on the White House, a symbolic act of “walking the talk.”

Today, the photovoltaic industry thrives on a global scale, driven by more than just government incentives. The collaboration on the Carter family farm is a testament to the enduring impact of these trailblazers, showing how far we’ve come and how much potential lies ahead.

Josh Bessette is president and CEO of J&B Solar.

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David Burton, attorney with Norton Rose Fulbright and specialist in energy tax law, looks at tax credit transfer, domestic content, energy communities, prevailing wage and more.

It has been two years since the passage of the Inflation Reduction Act of 2022 (IRA), and like any complicated and multi-faceted policy, the IRA is a mixed bag of successes and failures. Let’s start with the successes.

The IRA created a tax credit transfer market, and it is thriving. Our firm has closed almost $5 billion in tax credits transfers across over 40 deals. For our deals, the high price is 97 cents on the dollar and the low is 83 cents on the dollar. Much of the difference in price depends on the quality of the indemnity that backstops the buyer’s purchase of the tax credits. The high end of the range has investment grade indemnitors/guarantors or a tax credit insurance policy, while the low end of the range has an unrated indemnitor that is not backstopped by tax credit insurance.

The Treasury issued final regulations about tax credit transfers, but “the credit” really goes to Senator Joe Manchin (I-WVa) who decided that such things were better handled by the private sector than the IRS. In contrast, the activity around “direct pay” (i.e., a refund from the IRS) for tax-exempt project owners, clean energy component manufacturers, carbon capture and hydrogen projects is anemic. The eligible participants are, generally, avoiding direct pay due to concerns about the time it will take the IRS to process the direct pay requests and potential haircuts.

Tax credit transfers have been a success despite Treasury’s regulations consistently favoring tax policy over stimulating clean energy. Examples of that include the approach to the passive activity loss rules that limit the ability of individuals to buy tax credits that is even stricter than the passive activity loss regulations themselves: the transfer regulations preclude an election to “group” hours for an individual to reach the active threshold, while the passive activity loss regulations actually allow such an election for activities the combination thereof is an “appropriate economic unit.”

Further, Treasury’s regulations prohibit combining a lease pass-through (also known as an inverted lease) investment tax credit election with transferability (or direct pay), even though that election is provided for in the tax code.

The other gaps in the Treasury regulations are (i) that we don’t know whether the IRS is going to audit tax credit buyers or sellers (sellers make more sense, but buyers have the money) and (ii) we don’t know whether transaction costs for tax credit transfers are deductible.

Further, Treasury’s online registration portal is backed up, and Treasury is telling registrants that it can’t process registrations for 2024 until October because it has 2023 registrations it needs to process before the extension the buyers and sellers of tax credits that accrued in 2023 have to file their 2023 tax returns are up in September for partnerships and October for corporations. The resourceful tax credit transfer industry is finding ways to work around these issues.

A related goal of the IRA was to democratize tax equity. The IRA has made progress in that direction but has not fully succeeded. Thinly capitalized solar developers may be able to access the tax credit transfer market after paying a tax credit insurer, a tax credit transfer broker, a law firm and for investment credit deals, an appraiser. While well-capitalized solar developers can probably pull it off with a law firm and for investment credit deals an appraiser. Thus, the well-capitalized developers likely raise five cents or more on the dollar versus their thinly capitalized competitors. It may sound small, but over time it compounds and leaves the well-capitalized miles ahead.

The 10% tax credit adder for projects built in “energy communities” appears to have been mostly successful. For the most part, developers are able to determine whether their projects qualify for that adder and are able to monetize the adder in the tax credit transfer market. This is due to Treasury publishing guidance that is relatively clear and based on objective standards. Further, we are seeing projects developed on closed coal sites and in communities with a history of significant fossil fuel employment.

At the moment, the 10% domestic content tax credit adder is a split decision. The domestic content adder appears to have spurred the construction of a flurry of factories making solar modules and batteries, but most of those factories are not online yet.

Treasury’s original guidance on the domestic content adder was unworkable. To address that safe harbors were promulgated for solar, onshore wind and batteries. The safe harbors for solar and onshore wind seems to be viable. There is some cautious optimism about the safe harbor for storage. Technologies like geothermal heat pumps, fuel cells, renewable natural gas and offshore wind do not currently have a safe harbor and find themselves unsure about how to determine eligibility for the domestic content tax credit adder.

IRA failures

Grab a stiff drink and let’s turn to the IRA’s failures. First, based on anecdotal evidence, the prevailing wage and apprentice rules are not creating much value for the nation. Most folks building solar projects are already being paid wages not much different than the Department of Labor’s prevailing wage due to a tight market for skilled labor. Therefore, the prevailing wage rules are burdening the solar industry with concerns about a foot fault in their record-keeping resulting in large penalties or worse yet a reduction in the tax credits a project is eligible for by 80%, while not stimulating higher wages for skilled tradesman needed to build solar and other clean energy projects. It has created a cottage industry for consulting and accounting firms to verify the appropriate wages are being paid, but the nation was already facing a shortage of accountants. Let’s not even discuss the shortage of tax lawyers.

In terms of apprentices, it appears most projects are qualifying for an exemption from the apprentice requirements because apprentices are not available. Therefore, the well-intentioned rules do not appear to be spurring America’s young people to forego video games for learning a trade. Thus, the apprentice rules create a concern for project developers and their contractors about a costly tax credit foot fault while not spurring a renaissance in the trades. If solar and the other clean energy technologies are needed to save the planet from climate change, should we be burdening projects deploying these technologies with cumbersome requirements that are not resulting in more skilled tradesmen?

Finally, there are the proposed investment tax credit regulations. Those regulations fail to clearly answer some basic questions the industry has been asking for years like how much of a solar parking canopy qualifies for the investment credit. Further, Treasury has gone out on a limb requiring all equipment integral to a project to have a common owner and only allowing tax credits for repairs and upgrades if less than 20% of the improved project has its origins in the original equipment.

However, the investment credit regulations appear to have what is something of an unexpected gift. The Department of Energy (DOE) seems to have prevailed upon the Treasury to broadly interpret the rule about the investment credit for interconnection costs. The apparent motivation for this is to spur improvements to the nation’s anachronistic grid.

The statutory allowance for the investment credit on interconnection costs has a 5 MW capacity threshold. However, the proposed regulations appear to say that threshold is applied at the inverter level for solar and the turbine level for wind. For instance, it appears that a solar project that most industry participants would say has 200 MWs of capacity (i.e., it exceeds the 5 MW threshold) would qualify, so long as no inverter is serving 5 MW or more (e.g., there are 50 inverters each serving 4 MW). This interpretation appears to have been confirmed by the proposed section 48E regulations (i.e., the tech neutral investment credit). However, many law firms’ tax opinion committees are by nature conservative and are waiting to bless “will” level opinions under the traditional section 48 until Treasury confirms the favorable interpretation in the final section 48 regulations.

The implementation of the IRA has resulted in a range of policies outcomes. However, as is usually the case, the nimble and creative have faired well, while concerns about whether the nation is doing enough to address existential threat of climate change remain unabated.

David Burton is a partner at Norton Rose Fulbright. He advises clients on a wide range of U.S. tax matters, with an emphasis on project finance and energy transactions. He has extensive experience structuring tax-efficient transactions for wind and other renewables with particular expertise with respect to flip partnerships and sale-leasebacks. Earlier in his career, David was the managing director and senior tax counsel at GE Energy Financial Services (GE EFS) where he oversaw all of the tax aspects for more than US$21 billion in global energy projects.

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Throughout July, smoke from wildfires in Canada and the US West Coast significantly impacted irradiance across North America, while Hurricane Beryl and upper atmospheric conditions delivered unstable cloud cover across the central and eastern United States.

From pv magazine Global

Throughout July, smoke from wildfires in Canada and the US West Coast significantly impacted irradiance across North America, while Hurricane Beryl and upper atmospheric conditions delivered unstable cloud cover across the central and eastern United States.

Analysis using the Solcast API shows that the combined effects of reduced clearsky irradiance from smoke-related aerosols and cloud cover led to irradiance levels as low as 80% of long-term July averages along the Gulf Coast, East Coast, and the Midwest. In contrast, stable atmospheric conditions on the West Coast resulted in increased irradiance, extending across the Rockies as far as West Texas.

Whilst the fires raged, atmospheric aerosols have blown east and south, across the continent. Aerosols impact irradiance by scattering and absorbing radiation in the atmosphere, and reduce solar generation even on a day with no clouds. Peak ‘aerosol optical depth’, a measure of the impact of aerosols on irradiance, shows where the aerosol impact was strongest, and that smoke impacted all of the continent.

The below analysis of clearsky irradiance (a measure of irradiance before cloud or other weather phenomena) down up to 20% in some regions of Canada close to the fires, shows the large areas impacted as the smoke spreads through the atmosphere. Whilst in a normal month the impact of clouds and weather is much higher than that of aerosols, the intensity of this impact across July is reflected in the clearsky irradiance and the overall GHI.

In addition to the fires, a strong upper-atmosphere dipole created clear and stable conditions on the West Coast and unstable, cloudy conditions on the East Coast. This led to irradiance levels 10-20% above long-term averages in parts of British Columbia, Washington State, California, Utah, Colorado, Arizona, New Mexico, and Western Texas. While these clear conditions exacerbated the wildfires, prevailing westerly winds prevented the smoke from significantly impacting these states. Conversely, the same atmospheric conditions led to instability on the East Coast, reducing irradiance in the Carolinas, Virginia, and parts of New England. Hurricane Beryl further affected irradiance, casting a large shadow over the Gulf Coast and South-East early in the month.

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.

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New cloud computing technology can leverage industrial IoT protocols and extend the capabilities of SCADA with a software-first approach.

With the entrants of diverse distributed energy resources (DERs) and new utility requirements, optimizing and monetizing solar energy systems have become increasingly complex. However, monitoring and control technology are struggling to keep pace and meet these more sophisticated demands.

If the industry does not want to be hampered by its reliance on outdated monitoring and control technology, it needs to quickly leverage this window of opportunity to upgrade the capabilities of supervisory control and data acquisition (SCADA) by leveraging more advanced grid-edge, cloud computing, IoT-based technology that can support the integration of AI and help create a smarter grid.

SCADA is a technology that dates back to the 1970s and the solar energy industry originally made it a standard by adopting it from fossil fuel power stations. Over the past decade and a half, when solar was in its infancy and a small share of the grid, SCADA’s limited protocols met the grid’s requirements. But as the industry has evolved, SCADA is being stretched beyond its original design and is struggling to keep pace. Its drawbacks are beginning to hold back our industry’s advancement. For instance, as solar is increasingly coupled with batteries, EV chargers, and other types of DERs, SCADA’s lack of interconnectivity and interoperability with diverse hardware has increasing impact on compatibility and scalability.

Another example is that SCADA is more effectively used for daily operations versus storing big data that AI can leverage to improve long-term operations. Plus, the programmable logic controller (PLC)-based architectures do not support the more sophisticated controls increasingly being required by utilities. Overall, solar has outgrown the limits of SCADA and has quickly become too dynamic for a SCADA-only approach.

By using a software-first approach and connecting directly to onsite hardware, including inverters, batteries, RGMs, and other DERs, or through the manufacturers’ servers, new cloud computing technology can leverage industrial IoT protocols and extend the capabilities of SCADA. By overcoming the limitations of SCADA, a number of crucial benefits are unlocked for grid operators, O&M providers, IPPs, and asset owners, while also ushering in the age of a smarter grid.

The initial advantage of transitioning from a PLC-based hardware approach to a smart agent backed by cloud computing is that it drastically expands the types of controls that are available to clean energy assets. Unlike PLCs, that are simple logic-based programs pre-installed on a power plant controller (PPC) that has limited storage and memory, when controls are managed in the cloud there is no limit to how many controls or insights can be provided. In fact, it completely eliminates the concept of a control library because controls can continuously be added and optimized.

Instead of a static library, it becomes a growing and evolving tool that improves over time. This means that controls like arbitrage, peak shaving, frequency regulation, voltage support, peaker replacement, and energy shifting, can advance with the changing needs.

Another benefit of supplementing SCADA with cloud computing is being able to combine and analyze energy production data with thermal analysis to not only provide automatic alerts with minimal false positives, but also root cause analysis and precise recommendations for resolutions. This type of computing power is not available on site and is not possible with a SCADA-only approach.

That leads to a key secondary benefit of extending SCADA’s capabilities by augmenting it with cloud computing. SCADA is designed for managing power plants as siloed energy assets, but our grid is becoming more interconnected, and these distributed assets need to start working together in a more coordinated manner – both for grid stability and asset optimization. By managing controls in the cloud, distributed assets can be combined and managed as a whole. This completely surpasses the current single pane of glass concept for monitoring and controls that the industry has used as a gold standard up until now, and instead creates an advanced and cost-effective aggregator solution that is future ready.

While an aggregator offers many benefits on its own, it provides further benefit when artificial intelligence (AI) is added to the equation. By aggregating and analyzing data from multiple sites in the cloud, AI has access to more data points, enabling it to get smarter, faster; meaning better grid support and better monetization.

While SCADA has been hailed for its security, one of the reasons it is considered more secure is because of its limited functionality – limiting the opportunity for asset optimization and grid stability. Plus, its use of outdated and unencrypted protocols actually make it fairly simple to gain unauthorized access. But with industrial IoT, high-levels of encryption and verifications, significantly increase cybersecurity capabilities.

With the addition of next-generation IoT and cloud computing as part of the monitoring and controls toolbox, the solar industry can position itself to lead the entire energy industry into the era of a smart grid, where things like real-time energy trading will be ubiquitous. While a SCADA-only approach may have worked for simple unidirectional supply-side management with grid-following assets, it simply does not have the functionality to support grid-forming clean energy assets, which will herald in the age of an interconnected, dynamic, AI-powered grid.

Dekel Yaacov is the CTO and co-founder of enSights.ai, a SaaS platform. Dekel brings a wealth of experience in SaaS-based platforms and the cyber security field to drive the development of innovative solutions.

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There are a few ways to make efficiency-minded changes at home that reduce energy bills now and in the future.

With the hike in energy costs, many homeowners are looking for ways to save money on utility bills. While there are some obvious changes you can make – like turning off lights in empty rooms – believe it or not, there are many lesser-known things you can do to make a greater impact on your energy consumption.

Looking to expedite savings? Here are a few ways to make efficiency-minded changes at home that reduce energy bills now – and in the future.

Lowering the temperature and heating smarter

One of the biggest energy guzzlers in the home is heating, accounting for 50-60% of a household’s total energy costs. So, it’s no surprise that this is one of the main areas people focus on when looking to reduce energy. But how do you do this without compromising on comfort?

Lots of us tend to leave the heating on in rooms we aren’t using, or due to the way in which the system is built, have to heat the whole house, which leads to higher energy bills. But we wouldn’t leave the lights on in every room when empty, or leave the taps running, so why do we not take this approach with our heating?

There are many types of heating controls that can be programmed and personalized to your needs. As noted in recent research from UK-based BEAMA, upgrading from basic heating controls to a multi-zone smart heating system, where you heat rooms individually, can offer savings of over 30% on the average heating and hot water bill.

Additionally, intelligent thermostats can now detect when a window is open and automatically pause the heating. Even better, the latest home technology learns your behaviors to ensure you maximize energy savings without compromising on comfort.

Slaying vampire devices

Most of us are guilty of leaving devices plugged in when we’ve finished using them, but did you know that even on standby mode they consume electricity?

Yes – 23% of a household’s electricity is wasted by ‘vampire’ devices, appliances that consume lots of energy even when on standby mode. This includes gaming consoles, televisions, and smart speakers, just to name a few. Ensuring that they’re switched off helps limit unnecessary costs, but instead of manually having to go around your home to turn appliances off, smart plugs can make saving easier.

A smart plug can be easily turned on and off from a smartphone app, and some even allow you to set schedules for your appliances too. That means that if your plans suddenly change and a vampire device is still plugged in, you can easily disable it remotely, so you won’t have an eye-watering energy bill to come home to.

Automate your energy use

Homes are becoming highly complex energy environments, with tens or even hundreds of electrical devices all running at once. But very few of us have the expertise, time or desire to constantly check that we’re following good energy habits.

That is where home energy management systems (HEMS) come in. With the ability to automate all aspects of your energy – from production through consumption – they can help to lower energy bills.

One of the larger electrical loads commonly found in homes, in fact, are EV chargers. With electric vehicle sales increasing 35% year-over-year in 2023, more of us are installing EV chargers in our homes for easy, convenient charging. However, these chargers are one of the largest electrical loads, which can bump up your energy bills.

With a HEMS, the timing of your charge can automatically be shifted to, for example, run during the night when the utility costs are lowest. Additionally, a HEMS is great for homes powered by renewables, such as solar panels. Solar panels have the capability to generate surplus energy, and a HEMS can help you manage this extra power in a simple, cost- effective way.

The first is storing the excess in a home battery which you will then be able to use for things like charging your EV instead of using electricity from the grid. Additionally, you could also use the stored energy in the event of a power outage.

Alternatively, the surplus may be sold back to the grid, to be used in exchange for payment or credits contributing to greater saving on your electricity bills. By making your home efficient and energy secure, all from the push of a button, smart energy apps and home energy management systems can help reduce consumption by 7%.

Michael Lotfy Gierges is executive vice president for the Home & Distribution division at Schneider Electric. ​In this role, he is responsible for all aspects of Schneider Electric’s residential & small buildings offerings and solution development.

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To ensure sustainability and financial viability, the solar industry needs a critical reevaluation and enhancement of both technical protective measures and financial risk management practices for solar installations in hail-prone regions.

In recent years, the commercial landscape for renewable energy assets has been significantly altered by extreme weather events. Solar PV systems have been the most heavily impacted, with an increasing frequency of major loss events and associated insurance claims.

Since 2018, severe weather events in areas with substantial solar deployment such as the northeastern U.S., California and Texas, have prompted insurers to tighten terms and conditions. The result has been a sizable increase in insurance premiums, sometimes by as much as 400%, accompanied by deductible requirements of up to $1 million or 15% of the physical damage limit. More critically, insurance coverages for hail damage have been capped between $15 million and $40 million regardless of project size. Consequently, for large renewable assets with capital expenditures exceeding $200 million, the insured value only represents a fraction of the potential loss.

In addition, natural catastrophe (NatCat) coverages now often include exclusions like microcracking in PV modules. These changes are forcing the solar industry to confront a new reality where obtaining adequate insurance coverage presents a significant obstacle to project viability, and developers may be required to put up additional capital, securities, and/or guarantees to bridge gaps in coverage.

Hail risk

Many locations worldwide experience frequent hail, but only certain areas have historically experienced hail large enough to damage PV modules. In the U.S., severe hail is largely confined to east of the Continental Divide, up to the Great Lakes. In these regions, hailstones can exceed 2 inches in diameter and pose substantial risks to PV projects.

DNV estimates that since 2018, hail-related losses on PV facilities in Texas alone have surpassed $600 million. For instance, in May 2019 the Midway solar project near Midland, Texas, experienced significant hail damage to over 58% of its 685,000 modules, resulting in an insurance claim of ~$70 million. At the Fighting Jays solar farm in Fort Bend County, Texas, a hail event in March 2024 is expected to result in remediation costs reaching hundreds of millions, potentially exceeding 50% of initial construction costs.

Unfortunately, even current best-in-class mitigation strategies like automated hail stow and 1-inch hail resistance tests won’t protect against hailstones larger than 2 inches. To ensure sustainability and financial viability, the solar industry needs a critical reevaluation and enhancement of both technical protective measures and financial risk management practices for solar installations in hail-prone regions.

Hail size in USA on a 200-year return period. Hail sizes specified are for a 3,600 sq mi area; solar sites are substantially smaller and should result in smaller hail on the same return period. Loss estimation tools and inaccuracy

Quantifying potential hail-related financial losses for solar assets is crucial for financial planning, financial model evaluation, and determining insurance coverage. Given the complexity, assessing and quantifying potential losses is highly challenging. Risk probabilities used in these assessments vary widely, from near certainty (100%, corresponding to a 1-year return period) to extremely rare events (0.001%, or a 100,000-year return period). Benchmarks are chosen based on the risk tolerance of project owners and investors. The 500-year return period is particularly critical for gauging the extent of potential extreme event losses.

Since 2018, efforts have intensified to quantify the financial impact of hail-related losses across these periods, largely through Probable Maximum Loss (PML) studies to stress-test financial models of assets and portfolios. However, DNV’s reviews suggest these studies may significantly underestimate potential damages, often by a factor of 2 but as large as a factor of 295. This discrepancy typically arises from underestimating hail size for the 500-year return period and by overestimating the effectiveness of mitigation strategies like tracker hail stow position or the resiliency of modules that have passed 1-inch hail tests.

It appears that hail damage at the previously mentioned solar projects exceeded PML estimates by a large margin; these cases underscore the need for a thorough re-evaluation of hail risk assessment. By enhancing the accuracy of PML studies and adjusting risk management strategies, the industry can better ensure the adequacy of insurance coverage and the financial sustainability of solar projects against the risks posed by hail.

Mitigation and financial impacts after loss events

When a solar farm sustains significant hail damage, the repercussions are substantial. The most obvious effects are financial stress from insurance policy deductibles, production losses, and mitigation costs outside of policy coverage, but financial consequences can extend to increased insurance premiums, liquidated damages during operational downtime, costs and fees related to offtake agreements, and legal expenses from litigation by downstream assets and insurers.

The repair process for damaged solar sites is costly and labor-intensive. Disassembling shattered modules and reassembling new ones can require up to three times the effort compared to the original installation. Even modules and equipment that appear undamaged require inspection, testing, and commissioning to confirm functionality.

The financial stability of the project will be jeopardized if project owners are unable to promptly repair damage and restart operations. Tax equity investors and tax credit purchasers who depend on consistent energy production will find their investments at risk. If the project relies on a federal Investment Tax Credit investment structure, tax credits are subject to recapture by the IRS within a 5-year period from the Placed in Service date for the portions of the facility that are not promptly repaired. While insurance firms have introduced products to help mitigate this risk, the impacts from inadequate coverage can be severe.

Risk transfer instruments

Effective commercial risk management and hedging solutions are essential for managing the risks associated with natural catastrophes. A key component is the use of transfer instruments that shift the risk from the project to another party. In addition to insurance policies, these instruments include parametric warranties, long-term service contracts, financial derivatives such as options and catastrophe swaps, event-linked bonds like catastrophe bonds and resilience bonds, captive and self-insurance strategies, insurance-linked loan packages, multi-year insurance policies or bond agreements, reserve funds, and other contingent products. As a testament to their effectiveness, these instruments are already comprehensively applied in mature energy industries such as oil & gas, nuclear, and hydropower.

Parametric warranties and insurance policies offer a way to transfer specific risks to equipment manufacturers or project contractors. For example, if a module manufacturer certifies that their modules can withstand hail up to 2 inches, any damage from hail of this size could be covered under the warranty. This can reduce overall project insurance premiums by transferring frequent, predictable risks to the manufacturer or installer, who are better positioned to manage these risks.

Long-term service contracts with original equipment manufacturers (OEMs) or Engineering, Procurement, and Construction (EPC) contractors are another risk management tool, typically used by the wind industry. These contract structures can also help solar projects transfer operational risks by ensuring that unexpected costs related to equipment failure or operational issues are borne by the service provider.

Catastrophe swaps and event-linked bonds provide financial protection against large-scale natural disasters. By allowing project owners to exchange their risk exposure with another party, potentially in a different geographic location or industry, catastrophe swaps diversify and reduce risk profiles. Event-linked bonds, such as catastrophe and resilience bonds, are designed to raise funds in the event of a disaster. These bonds may defer or forgive repayment obligations if a specific disaster occurs, thus providing immediate liquidity to manage the aftermath of the event. Together, these instruments form a comprehensive toolkit for solar projects to manage and finance the risks associated with natural disasters.

Mitigating operational risk

Despite an expected increase in extreme weather events, project owners can mitigate operational risk through technical hardening measures, and hedge financial risk with accurate loss estimations and innovative risk transfer instruments.

Project stakeholders can negotiate parametric warranties, insurance policies, and long-term service contracts with OEMs, EPCs, and insurers for both operational and pipeline projects. They can discuss financial derivatives, event-linked bonds, and contingent products with their financial teams, and have the option to explore contingent future insurance and credit facilities with insurance brokers and underwriters. At the corporate level, project developers and owners can consider diversifying risk management across various uncorrelated segments of the company, thereby enhancing overall company resilience.

Having a combination of mitigation measures in place—technical measures including hail smart stow strategies, and reinforced PV modules as well as insurance and financial hedges—will allow solar asset portfolios to remain financially bankable, sustainable, and profitable even in locations prone to hail events.

Hamid Gerami is a civil engineer with DNV. As a licensed professional engineer and a CFA candidate, Gerami brings more than eight years of specialized experience in solar project engineering, design, construction, and innovative financing.

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The grid needs to modernize to meet a booming demand for electricity, which is only predicted to grow even further in coming years. IEC Standards are key to help with the transition.

From pv magazine Global

Electricity demand around the world is expected to sky-rocket as we switch to electric-powered vehicles, heat pumps for our homes and pursue the vast digital transformation of society. Emerging nations are also expected to use an increasing amount of electricity as they industrialize and give their populations ever greater access to energy. While this massive switch over to electricity is expected to considerably reduce global greenhouse gas emissions and help in the fight against climate change, a mounting concern is that electricity grids won’t be able to cope with the increased demand.

Ringing the alarm bell

The International Energy Agency (IEA) started ringing the alarm bell with a report it claims is the first of its kind. Published in 2023, it states that the world must add or replace 80 million km of transmission lines by 2040, equal to all electricity networks installed globally today, to meet national climate targets and support energy security. The report identifies a large and growing queue of renewables projects waiting for the green light to be connected to the grid, pinpointing 1 500 gigawatts (GW) worth of these projects that are in advanced stages of development. This is five times the amount of solar photovoltaic (PV) and wind capacity that was added worldwide in 2022.

“The recent clean energy progress we have seen in many countries is unprecedented and cause for optimism, but it could be put in jeopardy if governments and businesses do not come together to ensure the world’s electricity grids are ready for the new global energy economy that is rapidly emerging,” says IEA Executive Director Fatih Birol. “This report shows what’s at stake and needs to be done. We must invest in grids today or face gridlock tomorrow.”

The World Economic Forum (WEF) also urges world leaders to take note. A recently published article by Marcus Rebellius, a member of the WEF managing board and an expert working for one of Europe’s biggest manufacturers of electricity and electronic devices, indicates that “while the generation of clean energy is important, digitalizing and expanding our electricity grids is also vital for the green transition. Only with smarter, digitalized and expanded electricity grids will we create a decarbonized, resilient and secure electrical network for a net-zero future.”

He warns that increasing the amount of electricity generated to meet the increasing demand is not the issue, but that the key problem is that the grid must be prepared to handle larger amounts of electric power. “Weak grid infrastructure, legacy issues and an ageing system can all hamstring the green transition irrespective of the latest floating wind turbines or gigantic solar arrays,” he says.

Pointing towards the solutions

Grids have become the bottlenecks of the energy transition. Rebellius points to several technology solutions that could help resolve those bottlenecks, such as digital twins, or the use of low-voltage networks. (For more on digital twins and the electricity network: Digital twins and the smart grid. For more on low-voltage networks, read Affordable, sustainable electricity for all.

Other options include massively increasing energy storage capabilities and the widespread deployment of smart grid technologies around the world. The IEC Electropedia defines the smart grid as an electric power system that utilizes information exchange and control technologies, distributed computing and associated sensors and actuators, for purposes such as the integration of the behavior and actions of the network users and other stakeholders as well as efficiently deliver sustainable, economic and secure electricity supplies. Adopting smart grid technology is viewed by many experts in the field as a cheaper solution for utilities than expanding or rebuilding legacy electricity grids, which would require massive investments.

Increased energy storage is a key requirement

At times of high electricity demand, extra electric capacity must be immediately available or the grid risks shutting down. One way of ensuring continuous and sufficient access to electricity is to store energy when it is in surplus and feed it into the grid when there is an extra need for electricity. Utilities around the world have ramped up their storage capabilities using lithium-ion supersized batteries, huge packs that can store anywhere between 100 to 800 megawatts (MW) of energy. California-based Moss Landing’s energy storage facility is reportedly the world’s largest, with a total capacity of 750 MW. These huge battery storage facilities are expected to increase as the demand for electricity soars.

Other reliable energy storage solutions are pumped hydro which currently accounts for more than 90% of the globe‘s current high capacity energy storage. Electricity is used to pump water into reservoirs at a higher altitude during periods of low energy demand. When demand is at its strongest, the water is piped through turbines situated at lower altitudes and converted back into electricity. Pumped storage enables to control voltage levels and maintain power quality in the grid.

Another option that is much talked about is to use electric vehicles (EVs) as a source of energy to deliver power to the grid. According to Frances Cleveland, who is a lead for cyber security and resilience guidelines in the IEC Systems Committee on Smart Energy (IEC SyC Smart Energy), “There are many research and pilot projects around the world that are deploying some form of bidirectional flow of energy (charging and discharging), either as vehicle-to-grid or vehicle-to-home with EVs, able to sell power to the main grid and even support the energy management of microgrids. One of the driving ideas behind these projects is to provide a means of storing energy in the EV from variable renewable resources, like solar and wind, for use at other times. This implies that EVs can actually be viewed as a type of distributed energy resource (DER).”

EVs can charge when renewable energy generation from wind or the sun is high or when there is a lower demand for electricity, for instance when people are sleeping. But when demand is high, or less energy is generated by the wind or the sun, the electricity stored in EV batteries could be put to contribution.

State of play for smart grids

According to the IEA, in a report that tracks the advancement of smart grids around the world, significant levels of investment in smart grid tech have been made in many countries around the world – even if much more needs to be done. Several examples are given, including the EU action plan Digitalisation of the energy system. The European Commission expects about EUR 584 billion (USD 633 billion) of investments in the European electricity grid by 2030, of which EUR 170 billion (USD 184 billion) would be for digitalization (smart meters, automated grid management, digital technologies for metering and improvement on the field operations). Another important source of information on the roll-out of smart grid tech is the Smart Grid Index, provided by a leading utilities group in the Asia Pacific and which is used by many experts involved in the field. According to Peter Jensen, the Chair of IEC TC 13 which prepares standards for smart meters, “The index provides an excellent view of the maturity of grid system operators in different regions of the world. It uses a grid modernization measure based on seven pillars,” he describes. (For more on IEC TC 13, read Peter Jensen’s interview in e-tech.)

IEC Standards to the rescue

IEC Standards help energy storage systems to interoperate and interconnect with the grid. They also pave the way for smart grid technologies to be used safely and efficiently. IEC TC 4 prepares standards for hydraulic turbines and has published IEC 60193 which specifies the requirements for pumped storage.

IEC TC 120 was set up to publish standards in the field of grid-integrated electrical energy storage (EES) systems to support grid requirements. The TC is working on a new standard, IEC 62933‑5‑4, which will specify safety test methods and procedures for lithium-ion battery-based systems for energy storage. IEC TC 69 prepares standards on electrical power/energy transfer systems for electrically propelled road vehicles drawing current from a rechargeable energy storage system. IEC TC 57 is the IEC committee that prepares core standards for the smart grid, notably the IEC 61850 series. They deal with substation automation, two-way information exchange, global control functions, renewable energy integration and cyber security, to name but a few. IEC TC 13 prepares key standards in the field of electrical energy measurement and control, for smart metering equipment and systems forming part of smart grids.

A subcommittee of IEC TC 8 prepares standards dealing with the integration of renewable energy systems in the grid. One of the four IEC Conformity Assessment (CA) Systems, IECRE (IEC System for Certification to Standards Relating to Equipment for Use in Renewable Energy Applications), is the internationally accepted CA system for all power plants producing, storing or converting energy from solar PV, wind and various forms of marine energy.

The IEC SyC Smart Energy helps to coordinate and guide the various efforts across these different IEC technical committees. It is for instance working on a document, IEC 63460, that will describe the architecture and use cases for EVs to provide grid support functions. Most of this standard will be concerned with identifying realistic EV charging and discharging configurations, and the communication and control between the various actors, grid system operators, aggregators, premises energy management and EV charging systems. The results from this document will hopefully help other IEC technical committees to take the grid-support capabilities of EVs into account as they develop their own standards.

The hope is that enough will be done in time to make sure the lights will be kept on as we move towards an all-electric and connected society. One certainty is that IEC Standards and conformity assessment will be called upon to play an ever-increasing role in ensuring we get there.

Author: Catherine Bischofberger

The International Electrotechnical Commission (IEC) is a global, not-for-profit membership organization that brings together 174 countries and coordinates the work of 30.000 experts globally. IEC International Standards and conformity assessment underpin international trade in electrical and electronic goods. They facilitate electricity access and verify the safety, performance and interoperability of electric and electronic devices and systems, including for example, consumer devices such as mobile phones or refrigerators, office and medical equipment, information technology, electricity generation, and much more.

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While it may take more time for solar energy to become an integral part of power generation across the U.S., utility companies can prepare now to capitalize on the opportunities ahead as the DOE initiative moves to transform the grid for generations to come.

The U.S. is facing record electricity demand, mostly driven by AI processing, hyperscale data centers, electric vehicles and hotter weather.

But our nation’s electric grid, built over 70 years ago, struggles to keep pace with this record demand. Utility companies are stuck in the middle and often limited by aging grid technology. While the grid has been improved with automation and emerging technologies, U.S. aging infrastructure struggles to meet modern electricity needs, including the incorporation of renewable energy resources and handling growing building and transportation electrification.

To address these limitations, the Department of Energy (DOE) recently released its “Liftoff” plan. This ambitious plan will deploy advanced grid technologies to increase transmission capacity and reduce carbon emissions.

Outlined here are three key actions utility companies can take to realize this plan and the critical role of renewables, primarily solar energy, in making it come to life.

1. Identify Interconnection Requirements and Standards

First, it’s important for utility companies to understand any existing interconnection rules and standards. These can vary by state or region, although the U.S. federal government sets the minimum requirements. Utilities who do not produce their own power should work closely with independent power producers (IPPs) to ensure all relevant parties are meeting these rules and standards.

Utilities and grid operators can develop their own interconnection standards, particularly concerning solar energy. For any utilities or operators who use solar energy, safety and reliability need to be at the center of plans. Protection and control systems need to be in place to prevent inverters from catching fire due to possible overheating. Utilities should also consider battery storage systems for their solar energy systems, which can supply power to customers on cloudy days or at night.

There are a few different interconnection scenarios that could result from the DOE’s liftoff plan, which utility companies will need to prepare for:

Replace: Plans to replace towers and power lines is the most expensive and time-consuming element of the plan. For utility companies, this can help with future electricity demands. In the near-term, this could result in being unable to deliver the power required by customers with fast-growing electricity demands such as data centers or electric fleets.

Reconductor: Updating power lines with advanced conductors can cost less than half the price of replacement for similar capacity upgrades. This is a viable middle-of-the-road option that can support increased electricity demand over a short period of time without significant upfront investment.

Re-dispatch (“Connect and Manage”): This option allows customers to connect to the grid with the understanding that their energy supply might be curtailed based on grid supply and demand. This is the least expensive and fastest option but could also lead to insufficient power availability and reputational damage.

It’s worth paying attention to organizations like IEEE, NREL, EPA, and Interstate Renewable Energy Council because they provide industry perspectives in the drafting of these rules and standards.

2. Determine Roles and Responsibilities

An updated grid will need clearly defined roles and responsibilities across the energy ecosystem, including responsibility for repairs and servicing. To help avoid a “who’s on first” situation in delivering these essential services, utilities and IPPs can work together to clarify ownership and responsibility of certain tasks. The point of interconnection and the demarcation line often determine these responsibilities, impacting maintenance, repair, monitoring and incident management.

Electric utilities are generally responsible for:

• Regular upkeep of infrastructure such as powerlines, transformers and substations to ensure reliable service;
• Feasibility and impact studies to help ensure new interconnections do not compromise the grid;
• Reliability studies to ensure minimal outages and to shore up demand needs.

IPPs are typically responsible for:

• Power-producing components and interconnections;
• Maintenance and repair costs (though these are defined by contracts between IPPs and third parties, with responsibility contingent upon the location of faults and component ownership);
• Developing new power generation projects, which include site selection, securing permits, financing, construction and commissioning of some power plants.

It is critical that utility companies and IPPs have a collaborative relationship, sharing data to better understand and predict demand patterns and servicing needs. Technologies like Supervisory Control and Data Acquisition (SCADA) systems and Phasor Measurement Units (PMUs) enable real-time monitoring and management of grid conditions. Other technologies, such as predictive analytics and machine learning, can forecast solar generation patterns and adjust grid operations automatically – ultimately helping utilities and IPPs get power to the right place at the right time.

3. Work With Sustainable Technology Partners

The grid has grown more complex with the integration of solar, wind and other renewable energy sources. Software will play an important role in ensuring the grid can use these sources efficiently.

The DOE regularly announces solar funding opportunities, such as the Solar Technologies’ Rapid Integration and Validation for Energy Systems (STRIVES) program, that utility companies can tap into to integrate solar energy and other renewables into the power supply. Working with the right technology partner is critical to helping secure funding, as well as navigate this transition.

Partners who can support quick and easy installations, particularly for undergrounding and microgrid initiatives, can support utility companies in securing appropriate funding to drive investment in new and existing technologies. Products like switchgear connectors that are easy to install and have a lower total cost of ownership can help the utility company show that it can both operate efficiently and be financially prudent. In developing short- and long-range plans, factor in solutions and materials that can improve reliability and longevity such as fasteners and cable ties that can stand up to demanding conditions and exposure and simplify and reduce maintenance.

Ultimately, partners who can bridge hardware, software and data can help utility companies balance power supply and demand, while reducing the overall carbon footprint of their operations.

Solar Energy: The Not-Too-Distant Future

Foundational to the DOE’s Liftoff Plan is the interconnectivity and collaboration across the energy ecosystem, with the ultimate objective of improving both grid resilience and incorporating cleaner energy sources. While it may take more time for solar energy to become an integral part of power generation across the U.S., utility companies can prepare now to capitalize on the opportunities ahead as the DOE initiative moves to transform the grid for generations to come.

Alan Tse is senior director, utility solutions segment, ABB Installation Products Division, which is part of ABB’s Electrification business. He works with utility companies to power a safer generation through end-to-end solutions with trusted brands that connect, protect and control power continuity. ABB Electrification is a technology leader in electrification and automation, enabling a more sustainable and resource-efficient future. Building on over 140 years of excellence, ABB’s more than 105,000 employees are committed to driving innovations that accelerate industrial transformation.

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It may seem counterintuitive to operators who are familiar with traditional grid management methods, but the key to stabilizing the destabilizing effects of more renewables on the grid is--more renewables.

Keeping the grid stable is priority number one for grid operators, and over the past century, various technologies and strategies have emerged and been implemented to assist with load management, frequency regulation, and black start capability, among others. Most of these solutions are designed to work with a grid characterized by high inertia provided by spinning generators. However, as solar PV and other inverter-based power generation resources increase in number on the grid, they often displace spinning generators, the source of high inertia, leaving grid operators who have small and islanded systems to manage low-inertia grids with tools designed for high-inertia grids. This doesn’t work.

One big problem for island systems with low inertia is that the rate of change of frequency (RoCoF) is faster on a low-inertia grid than on a high-inertia one. This means that the response rate to correct a frequency deviation must occur within milliseconds on a low-inertia grid, whereas a high-inertia grid can rely on that inertia to carry it through the first five to ten-second period before needing to rebalance. Traditional frequency regulation methods such as generator and load-shedding responses are simply not fast enough for low-inertia grids.

The solid lines on this graph depict the dropping frequency on low, medium and high inertia systems. As is demonstrated by the steep drop of the yellow (low inertia) line, the frequency drops much more rapidly on a low inertia system than on a high inertia (red line) system.

To combat this problem, low-inertia grid operators turn to traditional solutions, such as increasing the number of fossil-fuel spinning generators to compensate for the drop in system inertia. Then, because they need to keep the additional generator running so it is ready to respond to such an event, and this generator is producing electricity, the operators resort to curtailing the renewable energy generated by their inverter-based resources because they now have an excess of power supply. In addition to wasting generated renewable energy, this approach creates a vicious cycle that adds unnecessary redundancy, expense, and runs counter to environmental and sustainability initiatives.

Solving the inertia deficit

It may seem counterintuitive to operators who are familiar with traditional grid management methods, but the key to stabilizing the destabilizing effects of more renewables on the grid is—more renewables. And the key to managing more renewables is—software in the form of a high-speed, precise controller. The renewables can make up for the lost inertia by offering synthetic inertia in the form of rapid or fast frequency response, and the controller is the brains behind detecting grid disturbances and ensuring the inverter-based resources are dispatched within milliseconds to rebalance any deviations.

A critical part of this approach is to integrate a battery energy storage system (BESS). The BESS behaves as a shock absorber capable of absorbing or releasing power from/onto the grid to compensate for changes in production, load, or frequency. When a BESS is paired with a sophisticated high-speed controller, the BESS can be called upon to perform additional grid management functions, increasing its own return on investment. These additional BESS functions include:

• Energy shifting: Absorbing excess solar PV power during periods of high production and dispatching it during low production times. This reduces the need for curtailments, captures generated power that would otherwise be lost, and augments the ability to respond to demand spikes.
• Ramp control: Solar PV production is intermittent and can be highly variable during weather events when cloud cover can cause rapid peaks and valleys in power output. A BESS can absorb those peaks and bump up the valleys to smooth and stabilize power output.
• Frequency regulation: Providing fast frequency response to address the steep RoCoF on low-inertia grids is a snap as BESS power can be instantly dispatched to address a frequency deviation.

It takes a multi-level, high-speed controller to manage all these use cases in a single battery. The controller needs to be able to generate a plan in advance that factors in anticipated grid load requirements and be able to adapt that plan in response to current events. Without the kind of parallel processing capability that can learn, plan, triage, and command, the BESS might be full when it needs to absorb and drained when it needs to dispatch. Of course, it’s possible to have dedicated BESS units for each use case but given the amount of downtime that the BESS is idling in between use cases, it makes more sense to pack all the use cases into one. This saves capital costs and helps in instances where there may be physical constraints that prevent multiple BESS units from being installed.

So far, we’ve revealed that the ‘secret’ to keeping a highly renewable grid stable is to integrate a BESS + multi-level, high-speed controller onto the grid. But what about inverters, where do those come in?

What is a multi-level, high-speed controller?Microgrid controllers come in all shapes and sizes but escalate in complexity as the number of managed resources increases. A controller that manages a single generator is not very sophisticated and can be considered a single-level controller. Once energy storage, renewables, and traditional generating units are thrown into the mix, the microgrid’s configuration requires a multi-level controller. Adding load management, forecasting, and dispatching for economic benefit raises the complexity levels even more, as does layering several controllers in primary and subordinate configurations. Each additional generation resource and control configuration is considered a level, thus requiring a multi-level controller. Will grid-forming inverters help?

When it comes to tools made for the 21st-century grid, grid-forming inverters show a lot of promise. Unlike grid-following ones, grid-forming inverters don’t require a fully functioning grid to “follow” to determine their own set points. This makes them great for managing inverter-based resources on low-inertia grids.

When paired with renewable resources like solar PV or a BESS, grid-forming inverters can help with grid support services such as black start and frequency management. However, there are some services they can’t assist with, and worse, when multiple grid-forming inverters are configured on a grid, they can compete with one another to try to re-stabilize the grid after a disturbance, which results in more destabilization. So, they can’t offer a full solution to low-inertia grid woes.

What the inverters need is something in charge of all of them. That’s where the multi-level controller comes in again. A multi-level, high-speed controller establishes and enforces a control hierarchy over all the grid’s energy resources, empowering each resource to contribute when and as needed, as directed by the controller. It can work with both grid-forming and –following inverters and integrate with the grid’s existing resources. Plus, if it is both network- and equipment-aware, the controller will ensure operations remain within the system’s constraints.

With visibility over the entire grid and its resources, the multi-level controller can take a holistic approach and make real-time decisions that take the grid’s limitations and the operator’s priorities into account. That leads to fewer outages and more rapid restorations when unavoidable outages occur.

Islands wishing to reduce their reliance on fossil fuel power generation need to let go of traditional grid management methods and embrace the tools of the 21st-century grid. Solar PV, wind generation, high-speed inverters, and BESSs are all part of the new technology mix, and when combined with a multi-level, high-speed controller, have been proven in real-world island environments.

Tim Allen, CEO of PXiSE Energy Solutions, brings more than 22 years of experience across utility-scale solar, wind and energy storage projects, software controls, investor-owned utility, independent power producer and pure developer realms. His unique set of skills, beginning with an Electrical Engineering degree from CalPoly offers seasoned perspectives and relationships that position him to lead PXiSE into the future.

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By combining a rapid shift to 100% clean energy with large-scale deployment of carbon removal solutions, we can create a true climate restoration future - one with a healthy, livable planet for generations to come.

As clean energy professionals, we’re rightfully proud of the rapid progress being made in deploying solar, wind, and battery storage technologies. The plummeting costs and increasing efficiencies of renewables mean that greening the grid by 2050 is now a realistic goal. This is cause for celebration.

However, we must also reckon with an inconvenient truth: even if we achieve 100% clean electricity by mid-century, atmospheric CO2 levels are still on track to reach around 450 parts per million (ppm) by 2050 – far above the 350 ppm level considered safe for humanity. The painful reality is that the clean energy transition, while absolutely necessary, is not sufficient on its own to avert climate catastrophe.

This is the stark message of Peter Fiekowsky’s recent book Climate Restoration, which argues that we must go beyond emissions reductions to actually remove a trillion tons of legacy CO2 from the atmosphere. Only by restoring CO2 to pre-industrial levels below 300 ppm can we ensure the long-term survival and flourishing of human civilization.

Fiekowsky, an MIT-educated physicist and entrepreneur, contends that relying solely on emissions cuts to stabilize CO2 around 450 ppm is far too risky. Humans have never lived long-term with CO2 that high. The last time levels were similar was over 3 million years ago, when sea levels were 60 feet higher and global temperatures 5-8°F warmer. Allowing CO2 to remain elevated for centuries risks crossing irreversible tipping points in the climate system.

The good news is that CO2 removal at the necessary scale is technologically feasible and surprisingly affordable, costing an estimated $1-2 billion per year. Fiekowsky identifies four main approaches that could restore atmospheric CO2 to safe levels by 2050:

1. Ocean iron fertilization to stimulate plankton blooms that absorb CO2
2. Seaweed permaculture to grow and sink carbon-sequestering kelp
3. Synthetic limestone manufacture using captured CO2
4. Enhanced atmospheric methane oxidation

These nature-based and biomimicry solutions harness and accelerate the Earth’s natural carbon cycle processes. Importantly, they are permanent, scalable, and financeable – key criteria for viable CO2 removal approaches. When you consider that New York City (just one major coastal metro) is currently debating whether to spend $20 to $50 billion dollars on an ocean barrier system to prevent future storm surges from flooding the city, the $2 billion/yr price tag on climate restoration seems like a better bet.

As clean energy professionals, we must expand our focus beyond just greening the grid to include large-scale carbon removal. Here’s why:

First, it’s a moral imperative. We have an obligation to restore a safe, stable climate for future generations. Stopping emissions is necessary but not sufficient – we must clean up the trillion-ton legacy CO2 mess we’ve already created.

Second, it’s risk mitigation. Relying solely on emissions cuts without CO2 removal is an enormously risky bet on humanity’s ability to thrive in a radically altered climate state. Carbon removal gives us vital insurance.

Third, it’s economic opportunity. CO2 removal solutions like synthetic limestone can produce valuable products, creating new industries and jobs. The transition to a circular carbon economy will require major infrastructure investments.

Fourth, it’s technically synergistic. Many carbon removal approaches like ocean fertilization or seaweed cultivation could be powered by offshore wind or floating solar, creating virtuous cycles.

To be clear, carbon removal is not an excuse to slow down the clean energy transition – both are essential. But the clean energy community must broaden its vision to champion carbon removal alongside renewables deployment.

Specific actions we can take include:

• Advocate for updating climate policy goals to include restoring CO2 to pre-industrial levels (300 PPM of CO2 is worthy goal), not just emissions cuts
• Support R&D funding and commercial deployment of CO2 removal solutions
• Explore integrating carbon removal with renewable energy projects
• Educate ourselves and others on the need for atmospheric CO2 cleanup

The coming decades will be pivotal for humanity’s future. By combining a rapid shift to 100% clean energy with large-scale deployment of carbon removal solutions, we can create a true climate restoration future – one with a healthy, livable planet for generations to come. But we must act quickly and decisively. The clean energy industry has shown it can innovate and scale rapidly when needed. Now we must apply that same spirit to carbon removal. Our children’s future depends on it.

Tim Montague leads the Clean Power Consulting Group and is host of the Clean Power Hour podcast. He is a solar project developer, cleantech executive coach and consultant, mastermind group leader, entrepreneur and technology enthusiast.

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Taxpayers seeking to claim the highest available investment and/or production tax credits for renewable energy projects must comply with the prevailing wage and apprenticeship requirements.

Nearly two years following passage of the Inflation Reduction Act of 2022 (IRA), Treasury and the IRS released the unpublished version of the final rule (Final Rule) for compliance with the IRA’s prevailing wage and apprenticeship requirements (PWA requirements).

Taxpayers seeking to claim the highest available investment and/or production tax credits for renewable energy projects must comply with the PWA requirements. A taxpayer must ensure that laborers or mechanics employed by the taxpayer or any contractor or subcontractor in the construction, alteration, or repair of a qualifying facility comply with the PWA requirements.

The Final Rule concludes the federal rulemaking process for the PWA requirements. (Note: The Final Rule is scheduled to be officially published on June 25, 2024, and therefore this article relies on the unpublished version.)

The Final Rule will replace the previously-issued Notice of Proposed Rulemaking (released August 30, 2023) (NOPR), which replaced the Initial Guidance (released November 30, 2022). Overall, the Final Rule is generally consistent with the NOPR, providing helpful clarification on industry concerns raised in comments to the NOPR. However, the Final Rule expressly declines to address industry-specific concerns, emphasizing that determinations of compliance with PWA requirements will be made based upon specific facts and circumstances. It therefore leaves several questions open to interpretation, including whether commissioning work is subject to PWA requirements and to what extent certain post-operational work may be subject to PWA requirements.

Clarifications

First, with respect to when PWA requirements apply, the Final Rule provides two useful clarifications:

Its supplementary information notes that “unrelated third party manufacturers who produce materials, supplies, equipment, and prefabricated components for multiple customers or the general public” are not subject to PWA requirements. In other words, most suppliers (absent performance of construction, alteration or repair on a project site) will not be subject to PWA requirements.

It also clarifies that apprenticeship requirements only apply to the construction of a qualified facility, and do not apply to alteration or repair of a facility after the facility is placed in service. In other words, most operations and maintenance vendors will not be subject to apprenticeship requirements.

Second, with respect to payment of prevailing wages, the Final Rule outlines regulations consistent with the NOPR: A taxpayer must ensure that laborers or mechanics employed by the taxpayer or any contractor or subcontractor in the construction, alteration, or repair of the facility are paid prevailing wages for the specific type of construction in the geographic area where the facility is located. The definitions of “laborers and mechanics” and “construction, alteration or repair” provided in the Davis-Bacon Act (40 U.S.C. § 3141 et. seq.) apply to the PWA requirements. General wage determinations issued by the Department of Labor’s Wage and Hour Division on www.sam.gov provide the appropriate prevailing wages for PWA requirements. The Final Rule lists Form WH-347 (the Davis-Bacon form for certified payroll) as one example of a record that may demonstrate compliance with PWA requirements.

Notably, however, the Final Rule distinguishes prevailing wage requirements from Davis-Bacon Act requirements – noting that prevailing wage requirements pursuant to the IRA are not a mirror of the Davis-Bacon Act, but instead may be merely in harmony with Davis-Bacon requirements. Treasury and the IRS therefore declined to implement certified weekly payroll, public notice, and other Davis-Bacon Act requirements as part of the PWA requirements.

While the Davis-Bacon Act focuses on the “site of the work” to determine when prevailing wages must be paid, the Final Rule uses a similar concept of “the locality in which a facility is located.” The locality in which a facility is located is the physical place or places where the facility will be placed in service and remain – commonly understood as the project site. It also includes secondary locations where a significant portion of the facility is constructed, altered, or repaired – but excludes secondary locations for fabrication or manufacturing that are not established specifically or dedicated exclusively for a specific period of time to the facility.

Significantly, the Final Rule largely resolves the question of which prevailing wage applies to a facility. It confirms that the prevailing wage in effect at the time the agreement for construction, alteration or repair of the facility is executed is the wage that applies for purposes of the PWA requirements. The same wage general wage determination may still be used if the contractor is given additional time to complete its original commitment or if additional work is incorporated into the agreement that is “merely incidental,” which provides reassurance with respect to usual course of business change orders during construction of a facility. If, however, the agreement is modified to include “additional substantial construction, alteration or repair work not within the scope of the work of the original contract,” or if the agreement is modified to “required work to be performed for an additional time period not originally obligated,” including exercise of an option to extend the terms of an agreement, a new general wage determination will be required.

For wage determinations needed and not covered by a general wage determination, the Final Rule generally follows the NOPR’s outline for submission of supplemental wage determination requests to the Wage and Hour Division. The Final Rule notes that taxpayers, contractors or subcontractors may submit supplemental wage determination requests. Such requests should be submitted no more than 90 days before the expected execution of a construction contract (or at any time following execution), and will remain effective for 180 calendar days after they are issued (or for the duration of the time the supplemental wage determination is incorporated into the contract).

The Final Rule also provides that the Wage and Hour Division will resolve supplemental wage determination requests, or notify the requester that additional time is necessary, within 30 days of submission of a request. If a supplemental wage determination is issued after construction work has started on the facility, it applies retroactively to the date construction started.

Third, with respect to apprenticeship requirements, the Final Rule incorporates many proposed regulations from the NOPR, including the three-pronged approach necessary to comply: taxpayers must ensure the labor hour requirement, the ratio requirement, and the participation requirement are each satisfied.

Many of the ambiguities raised in comments to the NOPR regarding apprenticeship focused on the Good Faith Effort Exception, and the Final Rule addresses several of them. Requests made to registered apprenticeship programs must be made in writing and sent electronically or by registered mail. Initial requests must be made no later than 45 days before the qualified apprentices are requested to start work, and subsequent requests must be made no later than 14 days before the qualified apprentices are requested to start work. The content of each request remains as outlined in the NOPR.

The Final Rule extends the period between requests on which a taxpayer may rely on the Good Faith Effort Exception to a full calendar year. In the event a request to a registered apprenticeship program is either denied or not responded to, a taxpayer will need to ensure an additional request is submitted annually in order to rely on the Good Faith Effort Exemption. There is no limit on the number of requests that may be submitted to a program, and there is no requirement to make subsequent requests to the same program (or to follow up on requests that are not responded to).

If a request to a registered apprenticeship program is partially denied, in order to satisfy the Good Faith Effort Exception requirements, the requesting party must accept the qualified apprentices offered (and may then consider the remaining portion as labor hours performed by qualified apprentices). An employer-sponsored registered apprenticeship program may not be used by such employer to satisfy the Good Faith Effort Exception requirements, unless the employer submits compliant requests to at least one registered apprenticeship program that it does not sponsor.

Finally, the Final Rule outlines in a separate recordkeeping section a list of records that may be sufficient to demonstrate compliance with PWA requirements. It notes that taxpayers may satisfy such recordkeeping requirements by collecting and physically retaining the records; providing them to a third-party vendor; or having each party physically retain relevant records (unredacted copies of which must be made available to the IRS upon request).

It confirms again that taxpayers are entitled to a rebuttable presumption of no intentional disregard if a taxpayer makes the appropriate correction and penalty payments before receiving notice of an examination from the IRS with respect to a claim for the increased credit. While continuing to emphasize that findings of “intentional disregard” of the PWA requirements will be made based on specific facts and circumstances, the Final Rule also provides 15 examples (for prevailing wage compliance) and 13 examples (for apprenticeship compliance) of facts and circumstances that may be considered in such a finding, including whether the failure was a pattern of conduct, whether the taxpayer took reasonable steps to monitor, review and correct compliance efforts, whether the taxpayer incorporated provisions in its agreements requiring compliance with the PWA requirements, and what documentation and records the taxpayer collected to ensure such compliance.

The Final Rule also establishes a 180-day limit for the taxpayer to pay correction and penalty payments following a final determination from the IRS that the taxpayer has failed to satisfy PWA requirements.

Overall, the Final Rule provides helpful clarity to renewable energy developers and contractors enacting and enforcing PWA requirements throughout the industry. However, leaves open industry-specific questions such as what scope of work constitutes “repair” rather than “maintenance,” particularly during operation of a facility. It also fails to address whether on-site commissioning work constitutes “construction, alteration or repair” sufficient to trigger obligations to comply with PWA requirements. These questions will remain subject to assessment based on specific facts and circumstances, and prudent industry developers and contractors will need to carefully consider and document how they approach compliance with PWA requirements consistent with prudent industry practices.

Monica Dozier and Jennifer Trulock are partners at Bradley Arant Boult Cummings LLP and regularly advise clients on labor and employment issues in the renewable energy industry.

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In a new weekly update for pv magazine, Solcast, a DNV company, describes the possible consequences for PV plan and grid operators of a possible switch to La Niña conditions in North America.

From pv magazine Global

With signs of a possible switch to La Niña conditions, solar asset and grid operators will be looking to understand the impact this change could have on US solar production. Based on currently available data, the Atlantic hurricane season is expected to intensify to look more like a La Niña year, leading to more frequent hurricanes. La Niña years typically result in below-average solar irradiance in the Gulf of Mexico, while increasing solar irradiance along the Atlantic Coast of the USA, according to analysis using the Solcast API.

In La Niña years, the Gulf of Mexico historically sees irradiance levels up to 10% below the long-term average due to increased storm activity. La Niña, characterized by cooler sea surface temperatures in the equatorial Pacific, impacts the Atlantic hurricane season on the
other side of the continental USA by shifting weather patterns. The cooler temperatures in the Pacific shift the jet stream further north, reducing vertical wind shear in the Atlantic. Normally, higher wind shear suppresses hurricane formation by disrupting their vertical
structure. However, with reduced wind shear, more hurricanes can form and develop more intensely. These conditions lead to more hurricanes, convection and cloudiness in the Gulf of Mexico, resulting in decreased solar irradiance. Whether or not we actually see a shift to La Niña in 2024, these patterns are already forming, indicating a likely reduction in summer irradiance for the Gulf Coast.

In contrast, the Atlantic coast of the USA has historically seen up to 5-10% above-average irradiance during summer months in previous La Niña events. Despite the higher number of hurricanes that can transition into mid-latitude cyclonic storms along the East Coast, the
periods between these storms experience relative stability. In between these large storms, the reduced cloud convection and rainfall lead to longer periods of clear skies. These calm periods outweigh the impacts of increased hurricane activity, leading to higher average overall solar irradiance along the East Coast for summers impacted by this weather pattern.

Using this climate analysis, it is possible to apply these possible weather patterns to the current distribution of solar generation across the US. Analysis using the Solcast API shows that a typical La Nina summer would mean 2.7% more rooftop solar generation for the New York ISO (NYISO), and 2.1% for New England ISO (NEISO). In contrast, the large number of utility scale assets in the Electric Reliability Council of Texas (ERCOT) sees lower production in a typical La Niña summer, down by -1.6%.+

Grid Aggregation models are built using available production information, and applying Solcast’s irradiance data to those models. 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 350 companies managing over 300 GW of solar assets globally.

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As multifamily housing emerges as a key player in the solar revolution, it is poised to not only benefit from but also drive positive change in the clean energy landscape.

The recent announcement of the $7 billion Solar for All grants on Earth Day, April 22, 2024, heralds a significant milestone in the United States’ clean energy journey. With 60 awardees committed to delivering $350 million in annual savings to low-to-moderate-income (LMI) households, this initiative marks a pivotal moment for multifamily housing, historically underserved in the landscape of clean energy transitions.

Traditionally, multifamily housing has faced barriers in accessing solar energy initiatives. The sector’s dynamics, with multiple tenants and landlords, create what is known as the “split incentive” problem. Landlords often hesitate to invest in solar systems when tenants are the direct beneficiaries, leading to a gap in low-to-moderate-income access to solar energy.

However, recent developments present avenues for change. Initiatives like Justice 40 underscore the federal government’s commitment to directing resources to LMI households. Moreover, the Biden-Harris Administration’s emphasis on Solar for All signifies a fundamental shift towards inclusive clean energy policies.

[Read also Community solar increases energy equity, report finds]One of the key advantages of multifamily housing lies in its scalability. Portfolio-wide implementation allows for the efficient deployment of solar projects across numerous units, maximizing impact. Additionally, the national nature of real estate ownership facilitates state-by-state fund deployments, ensuring broad accessibility.

Innovations such as SolShare offer promising solutions for on-site solar generation and consumption, directly benefiting apartment renters. These technologies align with a vision where solar energy becomes as integral to apartment amenities as air conditioning or in-unit laundry.

Policy measures, including tax credits and solar mandates, provide further impetus for multifamily solar adoption. California’s Title 24 mandate, for instance, requires newly constructed multifamily buildings to integrate solar panels, signaling a proactive approach to address the split incentive challenge.

Looking ahead, initiatives like Solar for All promise a future where multifamily housing is at the forefront of the clean energy transition. By bridging the gap between landlords and tenants, these programs not only reduce energy costs but also contribute to environmental justice and climate resilience.

The $7 billion Solar for All grants represent more than just a financial investment; they symbolize a commitment to equitable and sustainable energy solutions. As multifamily housing emerges as a key player in the solar revolution, it is poised to not only benefit from but also drive positive change in the clean energy landscape.

Mel Bergsneider is executive account manager at Allume Energy, responsible for business development in the U.S. market. As the first U.S.-based employee at Allume, Mel leads the Australian startup’s expansion across its target markets in the U.S. Mel works closely with affordable housing providers, solar installers, and real estate developers to provide solar energy benefits to tenants.

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The brownfield credit is significant and, therefore, it behooves a project developer to understand the definitions and rules in order to avoid any potential liability while also qualifying for the credit.

The Inflation Reduction Act of 2022 (IRA) makes available several new financial incentives to encourage the installation of clean energy projects in economically stressed locations. One such incentive is a bonus federal tax credit for projects built on brownfield sites. The brownfield credit is available for wind, solar, geothermal, and other renewable power projects, as well as energy storage facilities, green hydrogen projects, and biogas manufacturing plants.

The brownfield credit is significant. Project owners receive a 10% adder on top of either a Section 48 investment tax credit (ITC) or a Section 45 production tax credit (PTC). A project qualifying for the base 30% ITC would earn an additional 10% ITC, for a total 40% ITC tax credit, while a project receiving the base PTC would earn an additional 10% increment on top of the PTC. Thus, a project qualifying for a PTC of $27.50/MWh would receive an additional $2.75/MWh.

A project developer that wants to qualify for the brownfield credit should be careful not to present a case that also exposes it to potential cleanup liability or environmental remedial actions, thereby undermining the economic value of the tax credit. The IRS has published guidelines that are helpful to understanding how to walk this hazardous line to sidestep potential liability and still qualify for the brownfield credit. Notice-23-45.pdf

What qualifies as a brownfield site?

A brownfield site is one of three categories eligible for a new “energy community” bonus tax credit. The other two categories are:

1. Areas that had significant employment related to oil, gas, or coal activities;
2. Census tracts or adjoining tracts in which a coal mine closed or a coal-fired electric power plant was retired after December 31, 2009.

The energy community tax credits were created to encourage developers to build clean energy projects at sites that are disproportionately found in historically economically disadvantaged areas, and to repurpose environmentally distressed properties while providing other economic benefits to the community.

For purposes of receiving the tax credit, the IRS defines a “brownfield site” differently from the definition used by the Environmental Protection Agency (EPA) for Superfund liability and federal brownfield cleanup purposes.

The IRS definition of brownfield site is found in Section 39(A) of the Comprehensive Environmental Response, Compensation, and Liability Act of 1980, or CERCLA, 42 U.S.C. § 9601(39)(A). The IRS defines a brownfield site as:

Real property, the expansion, redevelopment, or reuse of which may be complicated by the presence or potential presence of a hazardous substance, pollutant, or contaminant (as defined under 42 U.S.C. § 9601) and certain mine-scarred land (as defined in 42 U.S.C. § 9601(39)(D)(ii)(III)). A brownfield site does not include the categories of property described in 42 U.S.C. § 9601(39)(B). Notice-23-45.pdf.

The Section 39(B) exclusion generally covers Superfund sites and other contaminated sites that are currently the subject of a court or administrative cleanup order, consent decree, or closure or removal action under designated federal laws.

Unlike the EPA cleanup program, the brownfield definition under the IRA does not include contamination from Controlled Substances (i.e., chlorofluorocarbons and other ozone-depleting substances) or petroleum products.

The EPA, however, recently expanded its definition of hazardous substances under CERCLA to include polyfluoroalkyl substances, otherwise called “PFAS.” PFAS are a group of chemicals found in a wide variety of consumer products, commonly referred to as “forever chemicals” due to their persistence in the environment.

The inclusion of PFAS in the brownfield definition significantly expands the number of potential sites that could be eligible for the brownfield credit. By the same token, it raises the risk that developers qualifying for the brownfield credit due to the presence of PFAS could end up becoming potentially responsible parties in a cleanup obligation under CERCLA. The EPA has carved out exceptions to incurring such liability. The prudent approach, however, is to carefully thread the needle to avoid opening up a project to this cleanup obligation in the first place.

Applying the safe harbor rules

The IRS definition of a brownfield site has three parts. The taxpayer must show:

1. The presence or potential presence of a hazardous substance, pollutant, or contaminant on the site.
2. That the presence or potential presence “complicates” the site’s reuse or redevelopment.
3. That the site does not fall within the excluded category of properties in CERCLA Section 39(B), i.e., sites designated as Superfund sites or that are the subject of a court or administrative cleanup order, consent decree, closure, or removal action.

To simplify the process of qualifying for the brownfield credit, the IRS has established three “safe harbor” categories that it will consider as brownfield sites if a project satisfies any one of the categories and the site does not fall within the Section 39(B) exclusions:

1. The site was previously assessed through federal, state, territory, or federally recognized Indian tribal brownfield resources as meeting the definition of a brownfield site under 42 U.S.C. §9601(39)(A). Examples of these sites can be found in the category of Brownfields Properties on the EPA’s Cleanups in My Community website or on similar websites maintained by states, territories, or for federally recognized Indian tribes.
2. An ASTM E1903 Phase II Environmental Site Assessment (Phase II ESA) is completed for the site using the most currently applicable ASTM standards that confirms the presence on the site of a hazardous substance, pollutant or contaminant as defined under CERCLA.
3. If the project has a nameplate capacity no greater than 5MW (AC), an ASTM E1527 Phase I Environmental Site Assessment (Phase I ESA) has been completed for the site using the most currently applicable ASTM standards, and the Phase I ESA identifies the presence or potential presence of a hazardous substance, pollutant or contaminant as defined under CERCLA.[3]

How must a contaminant “complicate” use of a site?

The IRS safe harbor guidelines provide a straightforward way to qualify for the brownfield credit. Notably, the guidelines do not explicitly require a showing that the second prong of the statutory brownfield definition is satisfied, i.e., that the contaminant “complicates” reuse or redevelopment of the site.

The IRS seems to suggest that if one of the safe harbor conditions has been met it will presume that the “complicates” prong is satisfied (The IRS “will accept that a site meets the definition of a brownfield site…if it satisfies at least one of the [three safe harbor] conditions and the site is not described in [CERCLA Section 39(B)].” Notice 2023-29.)

It nevertheless may be prudent for a taxpayer to provide evidence that the presence of contaminants at the site complicates its development or reuse. Such a showing also will be necessary where a project does not fit into the safe harbor categories.

The word “complicate” is a fairly broad term and is not defined either in the IRA or in CERCLA. The term, however, has been interpreted by the courts and the EPA in the context of CERCLA’s brownfield definition. It has been construed to mean “can add cost, time or uncertainty to a redevelopment project,” or make redevelopment “more complex, involved, or difficult in some way.”

These cases make clear that the phrase “may complicate” does not have to rise to the level of a recognized environmental condition, or REC, which can trigger a cleanup obligation or remedial action under federal or state environmental laws.

Thus, the New York Court of Appeals in Lighthouse Point, interpreting the CERCLA brownfield site definition, held that the “statutory definition does not, on its face, mandate the presence of any particular level or degree of contamination.” Rather, the property will qualify as a brownfield site, “as long as the presence or potential presence of a contaminant within its boundaries makes redevelopment or reuse more complex, involved, or difficult in some way.”

There are several ways to potentially demonstrate how the presence of a contaminant will increase the cost or otherwise make redevelopment of a site more difficult. An environmental consultant who finds the presence (or potential presence) of a contaminant in a Phase I or Phase II ESA, for example, can recommend that the developer or landowner:

• Use protective equipment or take other precautionary measures for workers on the site.
• Exercise caution and take protective measures to not unduly disturb soil or groundwater when installing e.g., project foundations, pilings, conduits, frameworks, etc.
• Undertake testing procedures or install monitoring equipment to check for contaminants.
• Place transmission lines and other conduits above rather than underground to avoid soil disturbances.
• Reroute roads and other easements to avoid potential contaminated areas.
• Apply other common-sense restrictions to site development such as prohibiting installation of drinking wells, residential structures, playgrounds, day care facilities, etc. on the property.

How close to a contaminated area must a project be located to qualify for the brownfield credit?

For the other two “energy community” categories, the IRS looks to see where the energy project will be built to determine whether it is actually “located in” an energy community. For example, the IRS rules use a nameplate capacity test to require that at least 50% of the project’s footprint is located within the census tract that had significant employment related to oil, gas, or coal activities.

Similar locational language does not appear to be applicable to brownfield sites. The IRS instead will permit a project to be located anywhere on a site where a hazardous substance, pollutant, or contaminant is present without requiring that the project be located on the contaminated portion of the site. The IRS states that:

A brownfield site is delineated according to the boundaries of the entire parcel of real property, the expansion, redevelopment, or reuse of which may be complicated by the presence or potential presence of a hazardous substance, pollutant, or contaminant. A brownfield site is not limited to only the portion of a parcel of real property that has or may have a hazardous substance, pollutant, or contaminant that complicates redevelopment.

Accordingly, if a project satisfies the safe harbor rules, or demonstrates that the presence or potential presence of contamination on the site may complicate its redevelopment or reuse, then the project will be eligible for the brownfield credit, whether or not the project is located on the contaminated portion of the brownfield site.

Merrill L. Kramer is an attorney and partner at Pierce Atwood in Washington D.C. He represents energy project developers, private equity companies, and institutional lenders on the development, financing, sale, acquisition, and investment in energy projects and portfolios. He has been ranked as one of the top energy lawyers in the country by Best Lawyers, Martindale-Hubbell and The Legal 500and recently was awarded the National Law Review’s “Go-To Thought Leadership Award” for his detailed and cogent analysis of the impact of the Inflation Reduction Act of 2022 on the clean energy industry.

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As solar projects are built increasingly in populated areas, community pushback has become a major risk to solar growth and achievement of climate targets. Yet by allowing solar installations to fit the land in its natural form, we can remove one of the most significant sources of pushback. We shouldn’t have to protect nature from solar development.

When you picture a solar farm, you might imagine a vast, flat desert landscape adorned with neat rows of solar panels.

For years, this image has epitomized the ideal solar site. However, as the demand for renewable energy grows, such “ideal” sites are becoming increasingly scarce. Traditional solar farm site selection criteria focused on flat topography as well as large, contiguous parcels, lack of land features, and mild climate. These criteria often limited the potential sites. Advancements in solar tracker technology are now reshaping the landscape of solar farm site selection and opening up new possibilities for developers.

For example, slopes beyond five degrees were historically considered “unbuildable.” This is because traditional solar trackers typically used continuous torque tubes that don’t flex. Even as torque tubes are being forced to flex, these trackers have limited ability to adapt to undulating terrain, requiring developers to grade the land before installation or use variable foundation reveal heights.

Flattening the land requires bringing in bulldozers and dump trucks, adding to the cost and complexity of the project, as well as creating a negative environmental impact. Some states require significant civil engineering and stormwater management measures to even approve grading, including large and expensive retention ponds, topsoil testing, revegetation measures, and more. Satisfying these requirements can be so expensive that developers may avoid the state entirely.

Solar sites can be disqualified for development for being located in a floodplain, wetland or protected area. The site may also have an increased risk of differential settlement due to earthquakes, soil instability, or a history of underground mining. With trackers more capable of following natural, or shifting, terrain, these issues can be managed.

Solar sites in areas at risk of hurricanes, flooding, and high winds have also historically been ruled out due to the potential damage they can cause to traditional solar trackers and other PV system equipment.

New tracking technologies eliminate the need for costly and time-consuming land grading. Unlike traditional solar trackers that require level ground, an all-terrain tracker can adapt to the land’s natural shape.

Even if a flat site is found, or created, to build a solar power plant, things can change. Over a project lifespan of 30 to 40 years, the ground under a solar project can shift and eventually break or damage long continuous torque tubes.

Think of a sidewalk — when the concrete is freshly poured, everything is perfectly flat and even. But over time, the ground shifts, raising or lowering tiles. Often the rigid sidewalk tiles crack over time from the relative motion.

The same can happen to a solar array if you install a rigid traditional tracker on land affected by differential settlement. By installing flexible bearings instead, the steel piles can shift without disrupting the plant’s performance.

Breaking the paradigm of the long, continuous torque tube required a string of innovations. In addition to the articulating hardware, we needed to reimagine the tracking technology and software controls to ensure that panels can optimally track the sun’s location given the changing slope from bay to bay.

Bartonsville Energy Facility near Winchester, awarded a gold medal for sustainable design by Virginia Gov. Glenn Youngkin. We had to develop tools to enable engineers and contractors to design a construction plan on non-flat terrain, since all of the prior software and modeling tools were only for flat terrain.

An all-terrain solar tracker also offers environmental benefits by reducing the amount of earthwork required. For example, the 170 MW Bartonsville Energy Facility solar project was recently awarded a gold medal by Virginia’s Department of Environmental Quality for going beyond regulatory requirements to improve the environment and promote sustainability. By using a flexible all-terrain tracker to fit to the natural landscape, the project was able to eliminate grading, exceeding the state’s notably strict regulations.

We need to continue to scale up solar development to reach net zero goals. As solar projects are built increasingly in populated areas, community pushback against solar development has become a major risk to our sector’s growth and achievement of climate targets. Solar development need not create negative local environmental consequences for the communities it’s built near.

By allowing solar installations to fit the land in its natural form, we can remove one of the most significant sources of pushback. We shouldn’t have to protect nature from solar development. With responsible development practices, we can actually protect nature with solar development.

One of the most significant benefits of all-terrain solar trackers is their ability to preserve the topsoil on agricultural land. Traditional solar installations often require the removal of topsoil, rendering the land unsuitable for farming in the future.

With all-terrain trackers, the rich topsoil remains intact and native plants can grow around the panels, maintaining and even improving the land’s agricultural value over time. A solar array can be used as a “cover crop” to protect the land for future generations from more permanent forms of redevelopment.

With their ability to adapt to the land’s natural shape, innovative trackers are making solar energy more accessible, cost-effective, and environmentally friendly than ever before. And they’re opening up a world of new possibilities for solar developers.

Yezin Taha is founder and CEO of Nevados, a solar tracker specialist. Prior to Nevados, Taha worked in engineering design and management, project development, energy consulting and bankability for solar projects from GE, Trane, and Black & Veatch. While at Black & Veatch, he discovered major unmet needs in the solar industry for a better mounting solution and he left to form Nevados Engineering to bridge that gap.

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The key to ensuring expected financial returns from the IRA comes down to a single word: compliance, and tax credit compliance is fraught with risk and complex to manage.

Excitement about the IRA continues to surge, with developers and tax credit investors poised to leverage unprecedented growth opportunities while accelerating the country’s clean energy transition. The IRA has attracted $110 billion in private investment and has created close to 100,000 jobs across the U.S.

The key to ensuring expected financial returns from the IRA comes down to a single word: compliance.

Tax credit compliance is fraught with risk and complex to manage. Tax credit investors and transfer buyers, including those utilizing the new T-Flip structures and corporate buyers leveraging tax transfer marketplaces, are all subject to IRA audit risk and the associated tax credit losses and/or expensive non-compliance penalties.

Who holds the risk?

In terms of risk management, tax credit transactions tend to focus on protecting the investor from recapture audit risk, but compliance risks affect the entire clean energy project value chain.

Risks across the value chain:

• Tax credit insurers ultimately hold claim risk, but do not have oversight over EPCs, sub-contractors, or supplier compliance.
• Investors do not have insight into whether or not their investments are compliant with IRA requirements.
• Project developers need to protect investors but don’t have a way of understanding or reporting whether engineering, procurement, and contractors (EPCs), sub-contractors, or suppliers are compliant.
• EPCs can’t guarantee prevailing wage and apprenticeship (PWA) compliance for projects.
• Sub-contractors do not have capabilities to comply with PWA requirements- they rely on contractors for this.
• Suppliers are hesitant to share the confidential cost data required for IRA domestic content compliance.

Risks passed across the chain

What can developers do to mitigate risks? They can provide sponsor indemnifications, require EPC contracts to guarantee PWA compliance, hire an accounting firm to do an AUP (Agreed Upon Procedures) review, and even offer to pay for insurance, but none of these methods fully protect investors. In other words, even with all of these efforts, a tax credit buyer could still fail an IRS recapture audit, which would trigger a cascading set of insurance claims and lawsuits through the entire project value chain.

Risk assessment

Pre-IRA, traditional energy project risk mitigation typically began with a series of questions about a developer’s track record and the project technology size and scope. The questions then focused on an EPC’s history, supplier bankability, and supplier technology risk.

IRA tax credits have created a new, additional layer of risk. Tax credits can be worth 30%, 40%, or even 50% of the value of a project, but need to be protected from IRS recapture audit risk with meticulous proof of compliance throughout a project’s lifecycle.

False comfort

False comfort regarding compliance risk is perhaps the biggest of all.

A tax equity investor or transfer buyer may believe that a contract or an insurance policy mitigates recapture audit risk, when in reality, the investor has significant exposure. These are heightened by four key factors:

1. Unchartered territory: In a typical investment risk assessment, investors have resources like credit rating agencies, historical track records, and market expertise to evaluate internal and external risks. Since guidance on IRA tax credit’ compliance is new and still evolving, investors don’t have the same level of expertise or policies in place to mitigate these new risks.

2. The role of insurance: Because tax equity investors and corporate tax credit transfer buyers assume responsibility post transaction for IRA compliance, it’s common to assume they can use tax credit insurance to cover the risks of IRS audit failure and the resulting loss of tax credits plus any penalties.

However, the market capacity of tax credit insurance is limited, tax credit insurance can be expensive, and insurance companies still expect stakeholders to have some sort of active compliance management in place to reduce risk. In short, insurance companies are not the first line of defense in IRS recapture audit failure.

1. The limitations of accounting practices: Traditional accounting firms typically have limited risk management capabilities for IRA compliance. Because formal audits are prohibitively expensive, they offer AUP reviews, spot checks, and monthly reviews. Still, since they don’t work directly with project EPCs or subcontractors, they can’t sign off on actual compliance for the project PWA requirements.

2. Post-build compliance- Federal PWA requirements extend beyond initial construction phase compliance. Any alterations or repairs throughout the audit recapture period need to meet PWA compliance. Without adequate PWA programs and systems in place to manage operations and maintenance (O&M) contractors, asset management teams can jeopardize tax credits for the entire project.

Tax equity investors and transfer buyers can protect themselves from audit risk and recapture by seeking a platform that was designed specifically for the IRA compliance requirements across the entire project value chain.

The risk management imperative

Tax equity investors and corporate entities utilizing the tax credit transfer market will be held accountable for any error, omission, or lack of compliance from project EPCs and subcontractors. Without an active compliance verification program in place from the onset of a project, investors are taking on significantly more risk than they may understand.

How to approach risk mitigation

Similar to other federal requirements, there are dedicated software platforms designed specifically for IRA compliance. When combined with guidance from compliance experts, they can provide the maximum risk mitigation possible.

To best protect against risk, a single platform should be able to manage all of the intricacies of IRA compliance over the lifecycle of a project. It should be able to ensure compliance for PWA and the adders for domestic content and energy communities. It should also manage compliance for PWA from initial construction to O&M-phase alterations and repairs, and provide protection from recapture audits from the full five year (ITC) or 10 year (PTC) recapture audit periods.

The future of compliance risk management

Investors with the foresight to recognize the risks of IRA non-compliance and require a third-party compliance management system in place prior to construction kick-off will be ahead of the game. By leveraging IRA compliance software and data analytics, investors will be able to fully leverage their IRA tax incentives and reduce their IRS recapture audit failure risk while contributing to a solar-powered, decarbonized future.

Charles Dauber is founder and CEO of Empact Technologies, an IRA compliance management platform. Empact delivers software and services that ensure utility and community-scale project developers and investors are compliant with Prevailing Wage and Apprenticeship, Domestic Content, Energy Community, and Low-Income Community requirements.

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Prices for tunnel oxide passivated contact (TOPCon) solar panels continue to fall. pvXchange.com founder Martin Schachinger explains how this will affect the sale of PV modules based on passivated emitter and rear cell (PERC) cells.

From pv magazine Global

There has been little movement in the price of solar modules in the low-performance class this month. However, there was a significant price adjustment for modules with efficiency levels of more than 22%.

The prices of these modules, which are now mainly equipped with n-type/TOPCon cells and double-glass, are increasingly aligning with those of mainstream modules. There are only upward outliers for some types with interdigitated back-contact (IBC) or heterojunction (HJT) technology, which are not considered separately in this analysis.

Production volumes in China for n-type cells and modules appear to have increased, but the new customs situation in the United States might already be having an impact. The question is, what will this do to the European market? Increasingly lower prices would mean that demand would continue to rise if it weren’t for several disruptive factors.

There are still larger stocks of modules produced in 2023 or earlier at distributors, but also among installers themselves. However, if these measure 2 sqm in size, they are selling poorly due to their low performance. Building owners usually want to see high performance and the latest technology installed in new systems, which makes it much more difficult for existing goods to sell.

Despite the expected reduction in module production and import volumes, more Asian modules are still reaching the European market than are currently in demand. This is causing inventories to grow, even for high-performance models, putting additional pressure on module prices.

Inventories of old modules, which were produced and purchased at significantly higher prices in the past, must therefore be continually devalued. However, this is not possible for all players, which means that there are very different prices for modules with PERC technology in the market. Overall, the price difference between these categories is increasingly shrinking.

Africa and Southeast Asia will probably also become oversaturated with modules and Chinese products cannot be sold to the U.S. market. One strategy that is becoming popular is to accommodate the soft factors of the commercial business – that is, payment and delivery conditions. Instead of offering modules at lower prices, credit lines are granted – often without requiring collateral – and free delivery is promised. However, it is doubtful that this tactic will work over the long term. Many smaller companies, in particular, are on the brink and imminent payment defaults cannot be ruled out.

Some suppliers also take refuge in online marketplaces, where they try to quickly sell their stock goods to international customers without incurring sales and marketing costs. But the competitive pressure there is also great and such goods can often only be sold at dumping prices. The other issue is that there is hardly any way to get to know the potential business partner in advance –you have to take what you get.

Misunderstandings can arise in business transactions, especially across national borders, and online platform operators are not always available to provide support and advice. The efforts involved in running an online business quickly become greater than purchasing or selling within an established business relationship.

My preference for using surplus older modules is clear: installing them in larger open-space or rooftop systems. The often smaller formats are not a bad choice, especially in areas with higher wind or snow loads. The material and assembly costs increase slightly in favor of better statics, but the easier handling makes up for the disadvantage.

And there is another undeniable advantage: the modules are already in stock and are therefore guaranteed to be available, meaning there can be no delivery problems and thus delays in the construction process. You may also find a few unsold inverters and cable reels, and then the components for your PV system are almost complete.

Once a system has been built and connected to a network, nobody is interested in whether the modules are of the very latest generation or not. In any case, the resulting assets can be sold.

Price points differentiated by technology in April 2024, including changes from the previous month (as of May 20, 2024). Image: pvXchange.com Martin Schachinger studied electrical engineering and has been active in the field of photovoltaics and renewable energy for almost 30 years. In 2004, he set up a business, founding the pvXchange.com online trading platform. The company stocks standard components for new installations and solar modules and inverters that are no longer being produced.

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With policymakers, utilities, and private enterprise working collaboratively to find solutions that work for a given state’s unique circumstances, we will surely see continued growth of virtual power plants.

Virtual power plants (VPPs) are attracting a lot of attention at the moment. Our upcoming 50 States of Grid Modernization Q1 2024 report documents numerous policy and program actions taken by several states, and our very own Autumn Proudlove moderated a session on VPPs at the 2024 North Carolina State Energy Conference. Additionally, the U.S. Department of Energy published an extensive report on VPPs last year, and even mainstream media is publishing articles on their potential. But what exactly are VPPs, and what are states doing to enable their development?

VPPs can incorporate a variety of technologies with different characteristics, leading to the challenge of adequately defining them. However, all VPPs share the common elements of quantity and controllability. At their heart, VPPs involve the aggregation of a large number of distributed energy resources (DERs), which can be collectively controlled to benefit the grid and potentially obviate a utility’s need to activate a traditional peaking power plant.

The Smart Electric Power Alliance (SEPA) groups VPPs into three general categories: Supply VPPs, Demand VPPs, and Mixed Asset VPPs. Supply VPPs involve electricity-generating DERs, such as solar-plus-storage systems, which can be aggregated and controlled as a single resource when needed. Demand VPPs build off traditional demand response programs by aggregating curtailable load at a scale that can have a meaningful impact on the grid. Mixed Asset VPPs include a mix of both supply and demand resources.

While the benefits of VPPs are clear, the pathway to greater deployment is not. However, state policymakers are currently testing a variety of methods to encourage their development. Common approaches include a mix of mandates for utilities to procure energy from VPPs, incentives for utility customers to deploy DERs and participate in utility programs, and market access reforms to allow third-party aggregators to participate. Different varieties of these approaches have been considered by several states and utilities over the past year.

California

The California Energy Commission (CEC) approved a new incentive program for VPPs in July 2023. The Demand Side Grid Support (DSGS) program compensates eligible customers for upfront capacity commitments and per-unit reductions in net energy load during extreme events achieved through reduced usage, backup generation, or both. Third-party battery providers, publicly-owned utilities, and Community Choice Aggregators (CCAs) are eligible to serve as VPP aggregators. At a minimum, each individual customer site participating in the program must have an operational stationary battery system capable of discharging at least 1 kW for at least 2 hours. Incentive payments will be made to VPP aggregators based on the demonstrated battery capacity of an aggregated VPP. VPP aggregators will then allocate incentive payments between the VPP aggregator and its participants based on their own contractual agreement.

California lawmakers are also currently considering legislation to stimulate the market for VPPs. S.B. 1305 requires the California Public Utilities Commission to estimate the resource potential of VPPs in the state, and to develop procurement targets for each utility to be achieved by December 31, 2028 and December 31, 2033.

Colorado

The Colorado Public Utilities Commission opened a new proceeding in September 2023 to explore third-party implementation of virtual power plant pilots in Xcel Energy’s service area. The Commission issued a decision in April 2024 requiring Xcel to issue an RFP for a distributed energy management system (DERMS), which would then be used to manage a VPP. The Commission stopped short of directing Xcel to file a VPP tariff, but speaks of their merit and suggests that Xcel should propose separate “prosumer tariffs” for residential and non-residential customers, including different aggregation capacities.

Georgia

A stipulation agreed to by the Public Interest Advocacy Staff and Georgia Power in its 2023 Integrated Resource Plan Update proceeding commits the utility to developing a residential and small commercial solar and battery storage pilot program that will provide grid reliability and capacity benefits. Georgia Power will work with interested stakeholders to develop the program and will file it for approval with its 2025 Integrated Resource Plan.

Hawaii

In December 2023, the Hawaii Public Utilities Commission approved a new VPP program for the Hawaiian Electric Companies (HECO). The Bring-Your-Own-Device (BYOD) will replace HECO’s Battery Bonus Program and will provide varying levels of incentives based on the value of the grid services provided. The program will only allow energy storage systems at first, but may be expanded in the future to include other DERs.

Maryland

The Maryland General Assembly enacted a bill in April 2024, which opens the door to VPPs in the state. H.B. 1256 requires investor-owned utilities in the state to develop pilot programs to compensate owners and aggregators of DERs for distribution system support services. The programs must be filed for approval with the Public Service Commission by July 1, 2025.

Michigan

Michigan lawmakers introduced legislation in 2024 related to VPPs. S.B. 773 requires the Public Service Commission to develop requirements for programs that would allow behind-the-meter generation and energy storage owners to be compensated for services they provide to the distribution system, including through aggregators of DERs. Utilities would then need to file applications for these programs during their rate cases.

Massachusetts

In January 2024, the state’s three investor-owned utilities filed their Electric Sector Modernization Plans (ESMPs) with the Commission for approval. The three ESMPs include plans to invest in DERMS and customer programs to advance VPPs.

For more states, click here.

Brian Lips is a senior energy policy project manager for the NC Clean Energy Technology Center. He manages the Database of State Incentives for Renewables & Efficiency (DSIRE).

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The requirements of measures such as the Uyghur Forced Labor Prevention Act (UFLPA) mean that solar panel prices in the United States can be twice as much as in Europe.

The past two years have seen a surge in PV module production. Clean Energy Associates (CEA) expects a 15% increase in annual solar production capacity to May 2025, versus around 8% more demand.

Several factors have contributed to this imbalance. The prospect of additional antidumping and countervailing duties (AD/CVDs) from the U.S. government, with new countries potentially affected, further complicates the picture for solar module buyers.

With an election scheduled in the United States in November 2024, there may be further policy upheaval.

Tariff changes

Developers have enjoyed falling prices for the first time in a while but new tariffs could drive up U.S. prices despite plentiful supply.

The biggest global solar module manufacturers are accommodating UFLPA restrictions to ship more product than anticipated and U.S. module production is expanding. New manufacturers based in the United States and other nations unaffected by AD/CVDs – such as Turkey and Indonesia – would take time to adapt to new trade policy, as happened after the UFLPA’s introduction.

Solar developers might need new suppliers and will have to double down on quality assurance and factory acceptance testing to ensure quality.

Technology in transition

The industry is in the midst of a transition from passivated emitter rear cell (PERC) to tunnel oxide passivated contact (TOPCon) solar. Heterojunction (HJT) solar is changing, even in PERC modules, with new materials making panels more weather resilient. Developers have historically struggled to purchase insurance for projects in hailstorm-hit areas such as Texas. Now, a film can be applied to PV module glass during production to strengthen products. Such technological shifts add additional risk to supply agreements, however.

Favorable terms

After a 24-month to 36-month seller’s market, a turnaround could reopen favorable terms and conditions for buyers. When manufacturers held the upper hand, developers had a tough time persuading them to be importers of record, and thus responsible for getting products across borders by meeting U.S. Customs and Border Protection (CBP) UFLPA traceability requirements. When shipments are detained, the importer of record is the responsible party.

If the buyer is the importer of record, they could face paying for products stuck in customs. If the supplier is responsible, payments don’t have to be made until panels are in-country.

The buyer could integrate a Delay Liquidated Damages clause in the supply contract to avoid such a scenario. If a shipment is delayed because it did not pass CBP requirements at the border, the seller would then have to reimburse the buyer for the additional costs incurred.

Product stagnation

Developers have to ask themselves, “If I do decide to lock in pricing, will these modules sit in warehouses for a long time?” That is one of the downsides of pre-planning and purchasing at lower prices. If a project is delayed, modules sit in warehouses where they may be repeatedly moved on forklifts, potentially causing damage. Developers can negotiate terms to limit risk associated with long-term storage, however.

There is also the risk of technology becoming outdated. Developers have learned the hard way in the past that when they have saved up a lot of equipment – transformers and modules – it has sometimes turned out that projects were canceled or delayed long enough for technology to evolve and for their product to become obsolete. As a result, developers have had to resell equipment for a fraction of the price they paid for it.

Regulatory uncertainty

Policy uncertainty presents another challenge. What will happen in the upcoming U.S. presidential election and how will that affect solar equipment supply and production levels? Developers have to plan for that uncertainty as well as thinking about keeping their projects on schedule.

The current surge in supply has occurred in such a brief period of time because of the tax credit incentives embodied in the U.S. Inflation Reduction Act (IRA) and because manufacturers are setting up facilities within the United States to avoid import restrictions.

The project development and construction worlds are currently not moving as fast as solar production and manufacturing. Even as challenges mount on the development side – projects are delayed, finance falls through, and planning regimes change – manufacturers are still moving forward at full speed.

The dynamics in Europe versus the United States are very different right now because of the UFLPA. There is no similar restriction in place yet in Europe, so the continental market is awash with low-cost modules. The pricing environment is in flux. Prices in Europe have dipped as low as $0.11/W of panel generation capacity. Prices in the United States still hover at around $0.24/W.

That difference in price is being sustained because many panel makers cannot yet export into the United States, as they are still trying to figure out the UFLPA import process. The industry is essentially setting up a differentiated North American supply chain.

Products may run through the same facilities but suppliers carefully segregate those that require full traceability to go to the United States. Many modules sitting in warehouses in Europe lack the full traceability required for United States import.

Engilla Draper is an expert in procurement and supply chains at Clean Energy Associates, which provides advisory services to developers and manufacturers in the renewables industry.

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The need to move away from fossil fuels is clear, but the path forward involves addressing both technological and economic challenges.

Climate change and air pollution rank among the most pressing issues of our time, impacting public health, ecosystems, and global economies.

The shift toward renewable energy has emerged as a pivotal strategy not only addressing environmental concerns but also promising a sustainable and economically feasible future.[1]

Solar energy, with its vast potential and increasing accessibility, stands at the forefront of this transformative journey. It promises a less polluted, more sustainable, and more equitable world.[2]

But, how exactly is this happening?

The problem with fossil fuels

Burning fossil fuels releases a significant amount of greenhouse gasses, which trap heat in the atmosphere and lead to climate change.

Plus, the byproducts of burning fossil fuels pollute the air, leading to health issues ranging from respiratory problems to heart diseases, contributing to millions of premature deaths annually.[

Fossil fuels have powered global development for centuries but at a great cost to our planet. They are the largest source of greenhouse gas emissions, which contribute to global warming and climate instability. Moreover, fossil fuels are finite.

According to MET Group, an integrated European energy company, estimates suggest that we could deplete our available reserves within the next 50 to 150 years if consumption continues at current rates. The urgent need to transition to renewable energy is clear, not just to combat environmental issues but also to ensure a stable energy future.

The need to move away from fossil fuels is clear, but the path forward involves addressing both technological and economic challenges.

Renewables forging the path

Unlike fossil fuels, renewable energy sources produce little to no greenhouse gasses or other pollutants when generating electricity. The benefits of renewables extend beyond environmental impacts; they are increasingly seen as economically viable.

Solar energy, for example, has become the cheapest form of electricity generation in many parts of the world, making it an attractive alternative to traditional power sources.

Growing role of solar energy

Fossil fuels dominate U.S. emissions according to the EPA but at the same time, solar power is increasingly becoming a prominent source of renewable energy globally.

Unlike fossil fuels, which are limited and contribute to significant environmental degradation, solar energy offers a boundless and clean alternative.

With technological advancements, solar panels are now more efficient and cheaper to produce, making solar energy a competitive and reliable energy source.

Challenges and opportunities for solar energy

While the transition to solar energy offers many benefits, it also comes with challenges. Integrating solar power into the existing energy grid, managing intermittent energy supply due to weather conditions, and the initial investment in solar infrastructure are significant hurdles.

However, according to the United Nations, these challenges are addressable with continuous innovation and supportive policies that encourage solar energy adoption.

In addition, the production and disposal of solar panels can be carbon emission intensive, especially if the energy used for these steps in the lifecycle of the panel are conducted in nations where the primary source of electricity is coal burning facilities.

Energy storage in lithium ion batteries has also come under scrutiny for the harmful impact the mining process can have on the ecology. However, experts agree that the gains from solar power outweigh the current drawbacks and innovation is helping to reduce and eliminate these every year.

Economic and social benefits

Adopting solar energy can also drive economic growth. It creates jobs in the manufacturing, installation, and maintenance of solar panels.

Solar energy can reduce electricity costs in the long term, being less susceptible to price fluctuations.

Additionally, solar energy can provide power to remote areas without access to the traditional power grid, improving living standards and promoting equality.

When solar panels are placed on existing structures, the environmental impact is lessened and the economical and social benefits are increased. Moreover, as the technology becomes cheaper and more widespread, the cost of renewable energy continues to fall, making it a financially attractive option for many countries.

Global action

Countries around the world are recognizing the benefits of solar energy. Numerous governments have committed to increasing their share of renewables in energy production.

Despite the benefits, the transition to renewable energy is not without challenges. One major hurdle is the intermittent nature of sources like solar and wind, which do not produce electricity consistently as fossil fuel-based power plants do.

Energy storage technology such as batteries is one solution. Policies that support renewable energy development, like subsidies, tax incentives, and regulations that phase out fossil fuels, are also essential to accelerate the transition.

With the right policies and continued investment in research and development, solar energy can meet a significant portion of global energy needs.

Georgette Kilgor is content director at State Solar, a foundation committed to advancing green energy technologies, educating businesses and residents on solar panels, reducing reliance on fossil fuels, and providing sustainability training to promote a healthier, more sustainable planet.

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In its first monthly column for pv magazine, the International Electrotechnical Commission (IEC) explains how a team of its experts is currently working on the definition of new standards for VIPV systems.

From pv magazine Global

Replacing polluting fossil fuels with the light of the sun to fuel a car almost sounds too good to be true. Solar cars – electric vehicles that feature solar panels – promise to offer a low-carbon way to drive with less need for electric vehicle charging stations.

Meanwhile, U.S. company Aptera recently announced it had raised over $33 million to fund the initial stages of production for its solar electric vehicle, equipped with 700 W of solar cells and able to drive over 600 km on a single charge. Already, more than 46,000 reservations have been made, though it is not clear when it will be available. Meanwhile, in Japan, the Puzzle van, a tiny electric van using solar panels to charge its battery, was unveiled late last year and is due to be available for purchase from 2025.

But for these projects to be viable, the quality, performance and durability of the solar panels need to be assured. IEC International Standards provide internationally agreed specifications and guidelines to ensure the quality, safety and efficiency of products, services and systems. Conformity assessment determines whether a product, service or process complies with specified standards. Standardization also provides a common language and framework fostering interoperability, efficiency, safety and overall reliability.

IEC TC 82: Solar photovoltaic energy systems, produces international standards enabling systems to convert solar power into electrical energy. These include the 14-part IEC 60904 series of standards, which covers all the requirements and measurements of photovoltaic (PV) devices and their components. Recognizing the need for specific guidance documents in this area, the committee has formed a project team, IEC TC 82 PT 600, for vehicle-integrated photovoltaic (VIPV) systems to develop two new technical reports in this area.

Convenor of IEC TC 82 PT 600, Kenji Araki said, “It is the quality and performance of the solar panel that will dictate the value of the solar car. A fair and scientific measure of this quality, therefore, is essential. Without an internationally agreed measure, it is difficult to ensure the safe and performant deployment of this technology. There will be a greater risk of fake or low-quality components that will not only hamper the advancement of the technology but create safety risks.”

Araki added that it is important to have practical and reproducible testing methods specific to VIPV because the context in which solar panels are used and thus behave is very different from those in other situations such as on houses or buildings.

For starters, vehicles are not static, so the amount of sunlight they receive can change dramatically. Thus, there can be sudden changes in power outputs when a vehicle moves in or out of a shaded area, for example, so technology needs to compensate for this. “We need a calculation shift,” he said, “and this can be complex and challenging to understand so it is important to have a detailed and comprehensive procedure for manufacturers to refer to.”

Araki explained the project team is currently focusing on standards and guidance for testing, operation modeling and energy rating, but they are also preparing to address other challenges. One of those is environmental and mechanical load tests. Unlike standard solar PV devices, the VIPV receives huge mechanical loads and experiences different environmental conditions.

For instance, the current photovoltaic modules can dampen vibrations of around 0.1 to 10 Hz really well, Araki pointed out, which are typical frequencies in architectural structures, but the vibration of the vehicle roof can be as high as 2,000 Hz. “In these situations, the molecular chains in the module sealing materials cannot catch up with the moving speed, so there is a significant risk that there will be resonance in the solar cell itself.”

The standards being used could also be applied in other settings such as drones and high-altitude platform stations (HAPS) and may help in rating PV power plants installed in mountains and forests. “In such installations, the shading loss in winter may be huge, leading to a lower performance ratio and therefore a higher cost of producing the energy. But it is hard to estimate. The new technical reports we are working on will help to solve this problem,” Araki underlined.

Clare Naden is a writer at the IEC, with more than 25 years of journalism and communications experience in New Zealand, the UK, Australia and Switzerland.

The International Electrotechnical Commission (IEC) is a global, not-for-profit membership organization that brings together 174 countries and coordinates the work of 30.000 experts globally. IEC International Standards and conformity assessment underpin international trade in electrical and electronic goods. They facilitate electricity access and verify the safety, performance and interoperability of electric and electronic devices and systems, including for example, consumer devices such as mobile phones or refrigerators, office and medical equipment, information technology, electricity generation, and much more.

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Solar Energy Manufacturers for America Coalition has a goal of rebuilding the solar supply chain in the U.S.

Installing solar panels can save consumers money and reduce harmful emissions that pollute our air and fuel climate change. But in just about every case, customers who buy solar view all solar panels as being effectively the same. The way they see it, the particular brand doesn’t matter; they all achieve the same result.

The problem here is that customers overlook a critical consideration: where the panels come from.

I’ve been in this industry a long time, but I’ve never seen a crisis like the one the United States solar industry is headed toward now.

Until fairly recently, most of the solar panels bought by U.S. homeowners were made here in America. But like many other industries, the solar industry has begun to rely on products imported from China. In 2023, the U.S. imported a record number of Chinese solar panels; 54GW worth, to be exact, according to S&P Global Market Intelligence. That’s an 82% increase from 2022.

Why the sudden change? Much of it comes down to 2022’s Inflation Reduction Act (IRA).

Most consumers know that the IRA incentivizes individual consumers to invest in solar panels, electric cars, and other sources of clean energy. Some know that it provides an incentive for domestic solar manufacturers. However, few know that it heavily subsidizes Chinese solar manufacturers.

As you might have guessed, even with incentives in place, American solar manufacturers are being squeezed out by their Chinese counterparts. In our space, the regulatory winds are flowing, but the one thing they aren’t regulating is where the solar panels come from. China is able to set extraordinarily low prices on its solar panels, and the U.S. simply can’t compete.

That probably sounds like a self-contained issue that only has negative effects on domestic solar panel manufacturers. Unfortunately, it has far-reaching consequences. More specifically, it threatens U.S. job growth, jeopardizes the country’s energy security, and causes more harm to the environment.

Solar power was innovated in the United States, and its growth has created well-paying jobs at every level of the process (from manufacturing to installation). The solar panel supply chain is lengthy and complex, so keeping the process within our country leads to gainful employment for more Americans.

As of 2022, there were 263,883 jobs in the U.S. that primarily focused on solar energy. If more domestic businesses take advantage of the tax credits and other incentives laid out in the IRA, that number will certainly grow.

Conversely, if domestic manufacturers keep losing business to Chinese importers, many of those jobs will disappear. There will still be a need to install imported panels, but every step of the supply chain and the assembly process will be (primarily) limited to China.

Hindered job growth is the first thing that comes to mind for many people when they think of keeping much of the solar supply chain in China. However, relying almost exclusively on China (or any other country, for that matter) for solar energy can pose a security threat.

One of the most surprising disadvantages of shifting solar panel production to China: it’s actually much worse for the environment.

One study found that manufacturing solar panels in China created 30% more greenhouse gasses than manufacturing them in the U.S. That’s because a large portion of Chinese electricity comes from burning coal.

This all might make it sound like solar has a gloomy future. Fortunately, it doesn’t, and that’s thanks to the Solar Energy Manufacturers for America (SEMA) Coalition.

The SEMA Coalition is a group of solar manufacturers with a unified goal: to rebuild the solar energy supply chain in the United States. Its members hope that the rebuilt supply chain will save U.S. solar customers money on their utility bills, create clean energy, open up new job opportunities, and make the country energy independent.

That’s not just talk. The coalition has already made a change for the better in the world of domestic solar manufacturing. Its members advocated for Solar Energy Manufacturers for America tax credits and other incentives to be included in the Inflation Reduction Act. The SEMA Coalition was successful — you can find these incentives in section 45X of the IRA.

The SEMA Coalition has taken the lead in that venture. But U.S. solar (and solar-adjacent) companies can help, too. We have a responsibility to make our consumers aware of the current crisis and help them understand why investing in American solar energy is so important.

We won’t lie and say the panels we sell are the cheapest on the market. They aren’t. But customers care about the environment, so we’ll tell them how buying U.S.-made panels cuts down on greenhouse gas emissions. They care about other people, so we’ll let them know how an all-American supply chain will create meaningful jobs that pay well.

The American solar industry has always been about innovation. If we keep that spirit, we can do more than just keep our solar supply chain within our borders — we can create a solar product that’s competitive on a global scale.

Randy French is the owner and founder of Independent Solar, a solar installation firm based in Arizona.

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This Earth Month is the ideal time to highlight the trend toward electrification and offer businesses and homeowners a viable path to get there.

Earth Month reminds us that the move from fossil fuels to electrification continues to gain momentum through incentives and regulations, and it’s inspired by companies and homeowners who are committed to reducing their carbon footprint. Another strong motivator for businesses and consumers is the opportunity to introduce energy efficiencies that yield cost savings – such as heat pump-enabled Energy Star certified appliances that are ushering in the clean energy future.

This Earth Month is the ideal time to highlight the trend toward electrification and offer businesses and homeowners a viable path to get there.

Homeowners needs to be educated on the concept of electrification. A recent nationwide survey conducted by a third-party on behalf of LG Electronics USA surveyed 1,579 U.S. homeowners in January 2024. They found that only 16% of American homeowners are currently familiar with home electrification.

Given the number of appliances and whole-house systems in a typical residence – along with renewables including solar panels and EV chargers in a growing number of households – the road to electrification can be overwhelming.

A logical starting point is investing in an energy storage system (ESS). It’s a move that applies to existing users of PV products and can be an attractive stepping-stone for those who may be thinking about or planning to install solar for their home or acquire electric vehicles in the future.

The nationwide survey also reports that among homeowners with residential solar, 25% currently have an ESS while 80% of those who do not yet have one say it is a future priority; 12% say it’s the number one priority.

ESS advantages

Tying a home’s energy footprint together with an energy storage system is an excellent step toward electrification that allows the homeowner to realize a number of tangible collateral benefits beyond reducing emissions from fossil fuel-based energy sources. It enables homeowners to manage their energy and take control of its use.

It’s smart to guide homeowners to understand that the ESS can be used independently from the grid and can charge during the daytime when electricity prices are lower. Stored energy can then be utilized during peak consumption hours when prices increase in many geographic regions.

It’s important for homeowners to know that an ESS can provide backup power which can be essential in the case of power outages. In fact, the nationwide survey revealed that 67% of U.S. homeowners experienced a power outage in the past year and half of them experienced multiple outages, some lasting hours or longer. In certain ESS models an LED display on the front of the system allows owners to check the estimated battery state of charge and encourages mindfulness of electricity use during power outages.

Advances in technology and design have made the ESS a more versatile and attractive alternative to the traditional backup generator. An all-in-one integrated system is incorporated into a complete smart home environment with appliances, electronics and HVAC systems. Management systems that allows the user to delegate how, where, and when the unit’s stored energy is used to maximize efficiency gives homeowners the ability to achieve pure independence from the grid, providing them with better control in managing their home energy needs.

This point is especially relevant to the surveyed homeowners who have expressed frustration over grid instability and concerns over the impact of extreme weather events.

Despite the need to educate the public at large on the benefits of ESS, the nationwide survey found that homeowners seeking to overcome the challenges of grid instability with an ESS are most interested in lowering their energy costs (90%). They also identify other appealing benefits of battery-powered ESS, including uninterrupted power supply (89%), less dependency on the utility (86%), potential to sell the energy back to the utility (84%), environmental benefits/sustainability (82%), and less dependency on fossil fuels (82%).

Incentives abound

In speaking with potential ESS customers, it makes sense to emphasize that investment in home electrification is rewarded by federal and state incentives. Residential ESS installations currently qualify for up to a 30% tax investment credit through the Inflation Reduction Act – a provision that not everyone knows will be in effect until 2033.

In addition, the U.S. Department of Energy has provided $8.8 billion in state funding for Home Electrification Rebates; these are expected to become available this year.

For business owners, a state-of-the-art, long-lifespan commercial ESS solution provides an all-in-one solution equipped with ready-to-deploy technology from storage with ESS, management with the PMS, and complementary systems such as HVAC. Commercial ESS can also qualify for up to a 30% tax credit through 2025.

The impetus can come from you

Interested homeowners are learning about ESS through various means: their own research, published news coverage on trends, products and incentives, and by speaking with neighbors and installers. Our research shows that homeowners want to be smarter about energy usage, fueled not only by a sense of responsibility to the planet but by the grim reality of rising energy costs. Two-thirds of our nationwide survey respondents reported rate hikes over the past year.

Those in the energy industry need to take the responsibility to help homeowners learn how to better manage their energy consumption and set them on a journey toward energy independence. By doing so, we can earn a position as a lifelong energy partner to our clientele. In the survey, two-thirds of those prioritizing ESS cited “a brand I can trust” as a highly important factor in their impending buying decision. Words to the wise during Earth Month 2024.

Jim Brown is senior manager, national sales, LG Electronics ESS. An industry veteran, Jim leads residential ESS business development in the United States for global innovator LG Electronics.

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Artificial intelligence models can be used during the solar pre-construction planning and design process, as well as afterwards to help with monitoring, weather forecasting, predictive maintenance and more.

The energy sector is generally considered to be fairly conservative when it comes to adopting new trends and technologies. After all, much of the energy we consume still comes from sources that have been used for hundreds of years — oil, coal, and natural gas.

However, in the recent push for sustainability in the energy sector, one technology emerges as a linchpin for the shift towards “green living”: artificial intelligence.

How AI will disrupt the energy industry for the better

Artificial intelligence seems poised to revolutionize the energy sector thanks to its superior data analysis capabilities. Data analysis is a fundamental aspect of any energy operation — from determining where the best sites for development are to how much energy has been consumed for billing. AI can perform all of this analysis at a much more efficient rate than human workers, allowing them to focus more of their efforts on implementing these solutions.

Artificial intelligence can also use the data it is fed to perform advanced predictive analytics. In the energy industry, this could prove invaluable, as the ability to better forecast consumption can allow energy companies to avoid the overuse of resources. Furthermore, as renewable energy resources have historically been somewhat unreliable due to their dependence on external factors such as weather, predictive analytics now powered by AI can allow energy companies to ease some of their concerns about the volatility of these renewable sources.

Using these tools, artificial intelligence could improve the sustainability of the energy sector by enabling the more efficient deployment of resources. Energy companies can both reduce waste and cut costs using analysis and forecasting generated by AI.

The most apparent use of artificial intelligence in the energy sector is “smart meters,” which help users better control their energy consumption and energy providers better understand and manage their load. Smart meters help the energy provider’s sustainability initiatives by reducing overall energy consumption, which will also benefit customers’ wallets.

Something that must be understood about the shift towards renewable energy sources is that, as more renewable energy sources are introduced, it makes the grid more complex to handle this increasing number and diversity of sources. In turn, more technology is needed to manage it. This is where artificial intelligence emerges as a particularly valuable innovation in the solar power industry — as a tool to help manage the distribution of resources on the grid.

AI in the solar industry

Some more specific applications in the solar power sector show even higher potential. As solar developers continue to expand some reach, some exciting use cases for AI technologies include:

• Searching for solar-generating properties: AI models can analyze data much more efficiently than humans, making them ideal for identifying solar-generating properties. An AI model can be trained to cross-reference properties on the market with characteristics set by the user — for example, climate, open space, and proximity to grid infrastructure — to quickly identify ideal sites for development and installation.
• Pre-construction planning and design: Artificial intelligence models can be used during the pre-construction planning and design process to ensure that solar power arrays are designed for optimal output. Producers can use this technology to test potential scenarios and layouts in advance, reducing the need for on-site labor and the expenses of on-site modifications and customizations.
• Real-time monitoring and data analytics: Solar power producers can use AI to power real-time monitoring and data analytics of their array’s output. This technology can help producers more efficiently identify and isolate any obstacles in their panels’ productivity, allowing them to conduct repairs much more quickly.
• Forecasting weather: One of the most exciting potential applications of AI in solar power is weather forecasting. Because the output and efficiency of solar panels are influenced directly by weather conditions, producers must be wary of any inclement weather that can interfere with the panels’ ability to generate power. Artificial intelligence can be used to predict weather conditions, allowing producers to adjust the amount of power being generated and stored during optimal conditions so that disruptions during suboptimal conditions can be minimized.
• Predictive maintenance: AI can also help enable predictive maintenance for solar panels. Regular maintenance is essential for solar power operations because a solar panel in disrepair cannot perform to its maximum potential. An artificial intelligence model can analyze historical trends and data on current conditions to indicate to producers when it is necessary to enlist a technician for maintenance.

The adoption of AI in the energy sector

AI can potentially revolutionize the energy industry with its advanced data analysis and predictive analytics capabilities. At this point, it is a matter of convincing the energy companies of the validity and necessity of these use cases.

By better understanding our consumption and needs, the energy sector can be better prepared to adopt renewable energy sources such as solar power. Artificial intelligence is the key to unlocking this deeper insight.

Ed Watal is an AI thought leader and technology investor. One of his key projects includes BigParser (an Ethical AI Platform and Data Commons for the World). He is also the founder of Intellibus, an INC 5000 “Top 100 Fastest Growing Software Firm” in the USA, and the lead faculty of AI Masterclass, a joint operation between NYU SPS and Intellibus. Forbes Books is collaborating with Ed on a seminal book on our AI Future.

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Innovative financing models and supportive policies are needed to make community solar financially viable and attractive to investors.

As the world strives to combat climate change and embrace sustainable energy sources, community solar initiatives that allow multiple participants within a defined geography to share the benefits of the energy generated are a valuable way to both support and drive the clean energy transition.

Community solar projects – sometimes called “solar gardens” or “shared solar” – give communities, including residents and businesses, access to clean, affordable and reliable energy while also allowing them to reduce their carbon footprint. Yet the pace of these climate-friendly, forward-looking power sources has slowed due to challenges in attracting skilled Engineering, Procurement, and Construction (EPC) contractors needed to get these projects up and running.

The Power of Solar for Communities

Community solar projects help local communities take control of their energy supply. By decentralizing power generation, communities can reduce their dependence on fossil fuels and large-scale power plants and help decrease greenhouse gas emissions. Community solar has socioeconomic benefits too, allowing a broader range of individuals and businesses to benefit from renewable energy, regardless of income level. This is especially important for renters, low-income households in disadvantaged communities, and those with limited rooftop access to solar panels, because they can access clean energy and save on their electricity bills through various financial incentives and credits that are afforded to community solar projects. Businesses can benefit from lower utility costs as well.

Community solar projects also stimulate local economies, creating job opportunities and driving investment in the region.

What’s Hindering Widespread Solar Expansion?

Developers face several unique challenges when it comes to getting community solar projects off the ground, often due to the unique nature of these installations.

They are often smaller in scale than their utility-scale solar counterparts, so they can be less financially attractive to larger EPC contractors who want to optimize their resources for economies of scale and make their projects more profitable. The distributed nature of community solar, with numerous small installations spread across various locations, can also present logistical challenges that make the projects much more complex and ultimately reduce their profit margins.

Solving the Financing Puzzle

Financing the community solar projects can be challenging as well, with upfront capital and uncertain revenue streams limiting options for developers. This, in turn, can further discourage large EPC contractors who seek stable and predictable ventures.

The relatively small scale of community solar projects compared to larger, utility-scale installations can make it more difficult for developers to qualify for and secure lender funding. Uncertainty in revenue streams due to fluctuating energy prices, regulatory unpredictability, and even the variations in how much a community will embrace the move to solar add to the complexity. It’s clear that innovative financing models and supportive policies are needed to make community solar financially viable and attractive to investors.

Offering portfolios of projects to Engineering, Procurement, and Construction (EPC) contractors can serve as a creative solution to help community solar developers obtain financing and drive down the cost of building community solar projects. By bundling multiple projects together, developers can leverage economies of scale, streamline procurement processes, minimize project risk, and negotiate more favorable terms with EPC contractors. This approach allows contractors to optimize their resources and reduce overhead costs, resulting in lower overall project costs. Additionally, portfolios of projects provide contractors with a steady pipeline of work, reducing their reliance on larger utility-scale projects and incentivizing them to prioritize community solar developments. Ultimately, this collaborative approach benefits both developers and contractors, facilitating the expansion of community solar initiatives and accelerating the transition to renewable energy at the local level.

Regulatory Landscape Adds More Challenges
EPC contractors, especially those who are used to dealing with larger, standardized projects often find that navigating the unique regulatory landscape of different communities remains a cumbersome area of concern as well.

For example, local zoning and land-use regulations can vary from jurisdiction to jurisdiction, and unlike utility-scale solar installations that are generally found on large tracts of unoccupied land, community solar projects can be sited in a variety of areas including both residential and commercial.

As a result, community solar developers are forced to navigate a patchwork of local regulations, which can differ significantly from one community to another. Zoning laws, aesthetic considerations, and community engagement requirements can vary widely, adding yet another layer of complexity to the development process.

Larger solar projects, often located in remote or designated solar zones, might have a more standardized regulatory environment, making it somewhat easier for developers to navigate the approval process maze. The decentralized nature of community solar, while beneficial for inclusivity, creates a unique set of challenges in complying with diverse local regulations.

Limited awareness and understanding of community solar projects among EPC contractors may hinder their willingness to engage with these initiatives, and they simply may feel more familiar and comfortable with traditional utility-scale solar projects

In a way, the beauty of community solar projects also brings their biggest challenges. But working with a solar EPC firm that understands the nuances of this market – that these projects are inherently localized and require engaging with diverse communities, each with a unique set of considerations and challenges, can make a huge difference. Community solar EPCs must adeptly navigate the intricacies of smaller-scale installations, recognize the importance of community buy-in, and tailor their project designs to suit local landscapes. Simply put: the more a community solar EPC better comprehends the significance of community engagement, diverse financing models, and the necessity for flexibility in project execution, the better able they are to craft solutions that resonate with the specific needs and aspirations of the communities they serve.

Next Steps: Attracting EPC Contractors

Community solar developers should proactively seek partnerships with EPC contractors who have experience in smaller-scale solar installations or who are willing to diversify their portfolio. Collaborative efforts can combine expertise and resources to overcome challenges and deliver successful projects. Community developers should also target EPCs with shared values, and where there’s a true desire to establishing partnerships based on a collective commitment to community engagement, environmental sustainability, and innovative financing models. Hosting joint workshops, participating in industry events, and fostering open communication channels can facilitate a deeper understanding of each other’s objectives and capabilities.

Community solar developers – and EPC contractors – must actively work to build relationships founded on transparency and a mutual dedication to effective project development. They must align on the importance and unique aspects of community solar and get excited about working together to push forward solutions that bring economic growth and clean power, while reducing carbon emissions.

Financial incentives and attractive returns on investment can be highly effective in enticing skilled EPC contractors to participate, and innovative financing models, such as crowdfunding or public-private partnerships, can help to secure needed capital.

Community solar projects are critical links to help drive the energy transition toward a more sustainable future. Their ability to engage diverse communities, reduce emissions, and foster economic growth makes them invaluable components of the renewable energy landscape. While attracting skilled EPC contractors can pose challenges, concerted efforts by forward-thinking community EPC developers to streamline processes, offer financial support, and provide education and training can go a long way in enticing contractors to participate. By working together, stakeholders can accelerate the adoption of community solar and pave the way for a cleaner, greener, and more inclusive energy future.

William Tualau Fale is vice president, pre-construction & business development for Babcock & Wilcox Solar Energy, Inc., a commercial, industrial and utility solar EPC firm, and a subsidiary of Babcock & Wilcox Enterprises, Inc.

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Dismissed by many in the solar industry as an overly complex, outdated technology, concentrated solar power (CSP) is set for a comeback thanks to a scaled-down, modular approach.

From pv magazine Global

CSP is experiencing a remarkable resurgence and India unveiled a 50% allocation for CSP in its renewable energy tender for the first quarter of 2024.

Scaling up CSP will bridge the gap caused by intermittent-generation PV and wind projects to help power the world’s most populous country with reliable, affordable, continuous renewable energy.

Rajan Varshney, deputy managing director of the National Thermal Power Corporation, India’s largest state-owned utility company said recently, “Now is the right time for CSP … As PV and wind capacity increases, increasingly more and more coal-based power will be required to make it firm and to supply electricity when the sun is not there. So by increasing PV, we cannot avoid coal unless we install CSP plus storage in Gujarat and Rajasthan.”

CSP’s resurgence may surprise industry insiders who consider the technology obsolete after problems with large scale sites, notably in California and Arizona.

While previous installations were massive, complex, custom-engineered, and not replicable, my company, 247Solar, has obtained finance for a modular version that solves for these challenges.

Our version operates on superheated air at normal atmospheric pressure. It stores energy using simple materials, not molten salt, and it can be mass-produced in 400 kW units for economies of scale.

The model shows promise to greatly shorten project cycles and resume the dramatic CSP cost reductions achieved in its early years and which slowed as the older technology matured.

Demand

Around-the-clock power demand has been rising because of growth in emerging economies and is accelerating due to data centers, cryptocurrency, and artificial intelligence (AI). As we move to electrify with electric vehicles, heat pumps, and industrial heat, CSP emerges as a viable solution to address those needs and provide continuous power.

Grid operators continue to grapple with the variability of photovoltaic and wind energy. Wind, if it blows at night, can help balance daytime solar but wind is much more variable than sunshine and requires long-distance, high-voltage lines to get to market, which can add cost and time to wind farm deployment.

Even large doses of lithium-ion batteries – meant to handle morning and evening peak loads, as gas peaker plants did before them – are nowhere near enough to store the energy it would take to keep the grid powered through the night and during bad weather, as coal plants have. Batteries may also feature conflict minerals, unlike our thermal energy storage systems.

CSP’s levelized cost of energy (LCOE) has fallen dramatically, by almost 70% since 2010, offering longer and more economical energy storage than batteries.

Concentrated solar has returned to projects that will pair it with PV to extend power output into the night, reducing overall LCOE by harnessing synergies between the two technologies.

Pioneers

Some of the high-profile early efforts at CSP got many things right, such as Abengoa Solar’s Solana plant near Phoenix, launched in 2013, or BrightSource’s Ivanpah plant in California, the world’s largest solar thermal site at the time, also in 2013.

Initial CSP plants focused the sun’s heat on a single point, reaching temperatures above 530 degrees Celsius. Our system pushes that limit to around 1,000 degrees Celsius.

Those pioneer sites also stored energy for six- to 12-hour operation at night, aiming for more straightforward, cost-effective technology than polysilicon-based PV modules.

CSP is no longer just huge installations of pipes and mirrors in the desert or towers as high as a wind turbine, however.

We are seeing new interest in 247Solar’s smaller, simpler, more flexible application of this technology.

Our turbines generate electricity from nothing more than superheated air so they don’t require a phase change of the energy from heat to steam as other CSP systems do.

Sustainable

We store the extra heat in cheap, inert materials such as sand, iron slag, or ceramic pellets. This eliminates the need for corrosive, high-maintenance molten salt, along with its other chemical and physical challenges.

Our proprietary thermal batteries provide 18-plus hours of storage for on-demand, industrial-grade heat and electricity. They can produce power during bad weather and, when fully discharged, the generators can even run on green hydrogen, natural gas, or diesel. With a capacity factor of 85%, however, that would occur far less often than in a system of PV plus batteries with a 40% capacity factor.

Our turnkey solution, which we call 247Solar Plants, is modular and factory-built for rapid cost reduction through mass production and easy, quick, on-site assembly.

Each module has 400 kW of generation capacity with 120-foot towers – half the height of earlier versions of CSP. With fewer moving parts than conventional CSP, our solar thermal power plant is also easier to maintain in a hostile environment.

We hold more than 30 patents worldwide, including a blanket patent just obtained in India, for our entire CSP system; as well as our proprietary solar collectors; ultra-efficient Heat2Power turbines, that use ambient air pressure; and inexpensive thermal battery systems.

Hybrid

This hybrid approach leverages the strengths of CSP and photovoltaics to generate uninterrupted power 24/7, with PV providing cheap electricity during the day while CSP stores its excess energy as heat for use at night.

Other companies, such as Heliogen, BrightSource Energy, and Acciona, are also pushing the boundaries of CSP with advancements in AI-enabled systems, alternatives to the shortcomings of molten salt storage, and lower-cost parabolic trough technology.

Potential applications for CSP include on- or off-grid combined heat and power, microgrids, ultra-heat for heavy industry, green hydrogen, and green desalination, as well as baseload power 24/7/365 – critical in fast-growing economies such as India’s.

“Emerging technologies such as solar thermal and concentrated solar power are essential for India to meet its renewable energy targets,” said India’s New & Renewable Energy Secretary Bhupinder Singh Bhalla, at the opening of the International Conference on Solar Thermal Technologies in New Delhi, in February 2024.

CSP is unmatched, especially when integrated with photovoltaics, for 24/7 dispatchability of flexible, dependable, and resilient zero-carbon power to meet the energy demands of tomorrow.

Bruce Anderson is a visionary in the solar industry for four decades, is founder and chief executive officer of 247Solar, which is commercializing a concentrating solar technology invented at MIT and which runs on superheated compressed air instead of steam. His career spans seven company ventures, a “New York Times” bestseller, and the American Solar Energy Society’s Lifetime Solar Contribution Award.

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Solar wiring that integrates easily in the field can simplify installation, enhance both quality and longevity, and improve overall project efficiency.

All stakeholders enter a commercial solar project with the goal of an on-time, on-budget delivery, but delays and overages are becoming widespread. Impeccable installation execution with an eBOS wire management system holds a key to timely and efficient delivery.

With an increasingly crowded solar market and more competition for solar projects, developers and EPCs can gain a competitive advantage by developing a track record of completed projects with minimal delays or overages. With the cost of a delay at $200,000 per MW, and PV solar installations delayed by an average of 4.4 GW each month, even a brief delay can take a significant toll on a project’s financials, and put profitability and capital management at risk.

While there are numerous external pressures that can delay a project, such as supply chain slowdowns or local ordinance issues, efficient installation is within a developer’s direct control.

The degree of installation success is driven in part by wire solutions. Wiring that integrates easily in the field can simplify installation, enhance both quality and longevity, and improve overall project efficiency. Wire solutions with a balance between customization and pre-fabrication can yield optimal results, including:

● The ability to pre-fabricate custom harnesses and source circuit lengths can significantly shorten installation time in the field.
● Wire stripping and adding connectors in the factory to controlled, manufacturer recommended tolerances will provide better longevity – enhancing a project’s financials in both the short-term, through faster installation, and in the long-term through better performance.
● Prefabricated and customized wire solutions have better consistency and reliability due to factory precision vs. manual fabricated on site.

The true cost of generic wire

While utilizing bulk wire solutions may seem like a fast and easy road to completion, it can slow down a project and cause installation delays. Every project has its own unique system design that requires a specific wire gauge, harness length and combiner box combination customized for each site. When evaluating wiring options consider the risks of using field-fabricated solutions, such as:

● Generic wiring that’s cut and fabricated on site lacks factory-assembled consistency, increasing the potential for connection issues and safety risks.
● Inconsistent tolerances and inefficient wire planning can necessitate procuring larger amounts of wire, creating budget creep and waste.
● Installing in the field requires more hours of skilled labor and entails on-site problem-solving instead of proactive planning ahead. This makes time and cost budgeting more unpredictable.

The bottom line – wiring options can make or break a project’s timeline and the quality of installation.

Assessing wire solution options

EPCs and developers that are assessing eBOS partners and wire solutions can benefit from these considerations:

● Assembly: Is assembly in-house, or managed via-subcontractors? In-house assembly allows a partner to have more control over quality and lead times.
● Design: Custom designed harness solutions can reduce the amount of wire required and therefore reduce overall eBOS cost.
● Plug-and-play: Does installation require manual cutting and problem-solving on-site, or can the solution be prefabricated for faster downstream installation and reduced labor costs?
● Project-specific solutions: What’s the degree of project customization? Problem-solving upfront and estimators who design tailor-made solutions will smooth installation and reduce risks of delays and budget overages.
● PV project lifecycle knowledge: Installation is only one piece of a much larger project with a much longer timeline. Does the wiring solution partner have a track record of success in complex PV projects, and understand the solar project lifecycle from upstream to downstream?

Wiring solutions can lay a foundation for ongoing success and an industry-leading reputation for timely, on-budget, and high-quality projects. As we move toward a clean energy future, competition among solar stakeholders is likely to increase, and developers and EPCs known for impeccable installation will stand out from the rest.

Case study: Cranberry fields forever

The Scenario: Installation execution was put to the test in Southern Massachusetts at a local cranberry wetland farm. Also known as cranberry bogs, these wetlands were designated as dual-purpose land (i.e., agrivoltaics). A leading solar developer was engaged to install 9-MW solar panels with 36-MWh storage over the fully-functioning bogs.

The Mission-Critical Task: Precision and accuracy were imperative, as installing solar panels over 150-year-old cranberry vines allowed zero room for error. The process required that arrays were high enough to prevent any damage to the cranberry crops below, while allowing for farming activities to take place without disruption. The complexities of this project simply could not be met with off-the-shelf-wire solutions.

The Challenge: A $53 million project set to power 1,800 homes was at stake. On top of that, there was a tight six-week delivery window, much shorter than a typical turnaround timeline. To meet the project requirements by the deadline:

● The solar arrays had to be mounted on 25 to 40-foot-long wooden,vwet terrain-resistant utility poles.
● The poles had to be driven 15 to 30 feet into the ground, keeping the solar modules at least 10 feet above the cranberry bogs. At this height, significantly more wire is required than the average solar project.
● The wiring solution needed to minimize long and heavy in-field installation activities to keep the cranberry bogs fully functioning.

The Solution: To ensure that the arrays would have solid foundations, durable racking structures, and be placed at an atypical height to minimize impact on crop growth, the deployed wiring solution had to be truly customized to every condition and variable: height, placement, quantity, human activity, and project timelines.

To meet the tight turnaround, the wiring was coordinated alongside the racking and module installations and the wiring was factory-assembled to ensure quick field installation. A total of 1,384 source circuit conductors (half positive, half negative) were cut to length and labeled in the factory with MC4 connectors installed on the panel end. It was blunt cut on the opposite end for field connection to combiners. The wiring was shipped on spools to the site, and the end-to-end connectivity of the wiring solution allowed for quick plug-and-play in the field.

The Outcome: The installation proceeded smoothly and efficiently, and the project was completed on time and on budget. Throughout the project, the cranberry bogs were fully operational and yielded a bountiful harvest.

Joe Parzych is eBOS product manager at Terrasmart. He brings over 15 years of product management experience to Terrasmart, focusing on wire management, product development, and production improvements. Terrasmart’s integrated eBOS solutions have delivered 23.5M feet or wire for solar projects across the country.

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PowerPanel offers a PV and thermal storage solution that combines simple, safe and easy to manage hot water with advanced thermoplastic technology and architecture.

New technology from an emerging company is adding hot water to the energy storage equation.

The surge in interest for storage alternatives beyond electro-chemical batteries—for reasons including efficiencies, longevity and recyclability– is raising the temperature on thermal technology as a means to store energy from PV and other sources.

Solar system designers and installers have long used hot water heating in tanks as a “diversionary load” to store excess PV-generated electricity. But such schemes required the installation of complex and costly plumbing infrastructure, between dedicated tanks and circulation systems. Newer thermal storage methods being discussed include so-called “T-Bat” thermal batteries using molten aluminum or alloys, hot silicon and thermo-chemical decomposition. But these either remain mainly in the concept or early adoption stages, or face challenges in implementation based on the state of present technology.

PowerPanel is taking a different approach: that of combining simple, safe, and easy to manage hot water with advanced thermoplastic technology and architecture—eliminating both the issues with old-fashioned steel tanks and the inherent risks of the newer exotic, inorganic thermal storage schemes.

PowerPanel, based in Oxford, Michigan, was founded in 2007 by Garth Schultz and Rob Kornahrens, to commercialize their PV/thermal technology. Prior to Power Panel, Schultz worked in clean vehicle development on projects involving GM, Chrysler and Ford, as well as clean agriculture initiatives in Canada. He heads up the manufacturing and engineering in the Michigan facility where all the products are made. Rob Kornahrens, CEO, was previously with thin-film solar panel maker Advanced Green Technologies.

PowerPanel’s Gen 20 thermal storage tank scraps the concept of the traditional steel tank, replacing it with durable, safe, stable and recyclable thermoplastics. The result is a lightweight, secure, and rapidly-deployable thermal storage solution that can be set up in minutes and lasts for decades.

The company bundled the PV module and thermal together in one panel with the idea of combining two renewable energy streams, photovoltaic and thermal heating (PVT). PVT has been tried in the past, but it usually involved a PV module with a thermal “catcher” fixed on the back. What Power Panel did was “encapsulate” the PV with a flat-plate glazed solar thermal production unit. It uses special materials developed for Power Panel, which gets molded into an enclosure; basically a PV ‘insert” is embedded into the thermal collector/circulatory architecture.

Along with collecting heat, it also cools the PV module and makes it even more efficient regarding electrical generation. The energy production output ratio of a PVT panel is roughly 1:4 PV and thermal, and about 2X decarbonization, compared to PV or thermal alone. Because it harvests solar energy from two energy streams, the hybrid PVT panel is over 80% efficient at capturing the sun’s energy with combined electricity and hot water generation, much more so than PV panels on their own (about 23% depending on the type).

According to PowerPanel, the large PVT array at peak can produce 2.7kW of PV electricity and 12.7kW of thermal (hot water or another fluid) at the same time. Both the foam storage tank and the hybrid PVT solar collector are covered by various patents.

The PowerPanel approach is based on replacing steel, glass and other materials with expanded polypropylene foam (EPP). A molded material, EPP has a fraction of the weight of traditional materials , yet has up to twice the insulation capability at as little as 1/5th the energy storage cost of conventional tank materials and up to twice the insulation capability—in fact, a Gen 20 Tank loses just a little over 2°C of heat over a 24 hour period. It also has superior impact and chemical resistance compared to other designs.

inside Power Panel’s Gen 20 Tank system. All the pieces fit onto a standard pallet easily handled by two people The patented PowerPanel Gen 20 tank is modular for ease of transportation and rapid on-site assembly. A standard shipping container can accommodate over 50 of the tanks for rapid deployment anywhere where needed. Since both the exterior and interior liner are made from non-degrading engineered foam and plastics, the tank can be installed indoors or outdoors, or even buried at grade.

A uniquely innovative feature is the tank’s configuration for assembly. It comes self-palletized and consists of an outer “hoop” and cover, into which the EPP foam sections are inserted along with a thermo-plastic liner. All the pieces needed fit on the footprint of a standard pallet, making it easy to move the tank into a building or up onto a rooftop— in fact individual pieces can fit through a very small entrance, and the heaviest of them is just 10 pounds.

The entire tank assembly’s total weight just a little over 100 pounds, meaning that two people can easily unload and manage one under any field conditions. And, the company reports that they can set one up in a matter of minutes.

The tank’s inventor Garth Schultz notes that “people in marketing always claim that something takes just ‘minutes’ without actually disclosing just how many minutes that is. But in the case of our Gen 20 Tank we’re being transparent: it takes two people all of 5 to 10 minutes—tops– to set one up. To say our design saves valuable installation time is the understatement of the decade.”

Schultz also points out other advantages to PowerPanel’s unique storage topology. “You can ‘cascade’ multiple tanks together using our connecting hardware to expand a system. Since the tanks aren’t pressurized no pressure vessel certification is required. Our system can take full advantage of the various tax and other credits out there. We also have a range of upgrades available, including heat exchangers and water-purification systems for medical and other field uses.”

The adaptable materials that form the PowerPanel tank structure cover the range of thermal applications, enabling either hot or cold storage from 200 F to as low as -25 F. Flexible options include customizing liners for different fluid use, depending on the need, the Applications for PowerPanel’s thermal storage and complete PV/thermal systems range from disaster relief operations to institutional and hospitality facilities—anywhere hot or cold pure water is essential to human health and well-being. For more information contact

Real world use

The large integrated system can supply enough solar thermal water to supply an average sized hotel, along with generate supplemental electricity, and systems can be daisy-chained. That configuration would be ideal for hospitals, campuses, and other facilities.

A Power Panel Gen 20 Tank and integrated PV/Thermal array (also from Power Panel and a patented design), on a hotel rooftop in St. Thomas, U.S. Virgin Islands. Some commercial users of the larger integrated system (multi PV panels and tanks) include Winward Passage, a resort hotel in Saint Thomas and BVQ Lofts in Cleveland, an apartment complex in Ohio.

The small system has seen placement in relief operations by NGOs, notably in Puerto Rico following a hurricane as well as in Ukraine, serving communities with electricity to stay connected as well as hot water for everyday living.

Mark Cerasuolo has spent nearly 30 years in the electrical manufacturing and renewable energy industries, most recently at Morningstar Corporation, a leading brand in off-grid solar components. His prior roles include marketing, training and product development with OutBack Power and Leviton Manufacturing.

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Industry experts share their insight on the state of the commercial and industrial power purchase agreement and best practices for executing successful deals.

Power purchase agreements (PPAs) have emerged as the go-to financing tool for commercial and industrial (C&I) solar adopters looking to avoid upfront costs and realize immediate energy savings. While the mechanics may seem complex, the core PPA value proposition is simple – install solar with no money down and pay a lower rate for clean electricity (than you pay for grid power) from day one.

On a recent webinar, leading solar financing experts Marc Palmer of Conductor Solar and Nick Perugini of Solaris Energy shared perspectives on the state of the C&I solar PPA market and best practices for executing successful deals.

According to Palmer and Perugini, the two most important criteria for a bankable PPA are 1) the ability for the customer to save money versus grid power; 2) the customer’s creditworthiness and long-term outlook; and 3) developers should focus on aligning with financing partners that have experience with similar project profiles in terms of size, location and offtaker type. Each investor has requirements and preferences for where they invest and how aggressively. The right fit can make the difference between the project getting built or stopping in its tracks.

Customer criteria for C&I PPAs:

1. Customer savings
2. Customer credit
3. Finding the right investor

Minimum PPA project sizes vary by financier, but typically start around 150-200 kW, with multi-site portfolios enabling even smaller projects to transact. On the large end of the C&I spectrum, virtually any project size is viable in today’s market. Across the U.S., projects from 20 kW to 20+ MW are getting funded, spanning everything between residential and utility scale.

| PPA project sizes | | 20 – 200 kW: | Small projects, may need to aggregate | | 200 kW – 2 MW: | Doable one by one with the right financier | | 2 MW +: | Often highly viable with the right financier |

Palmer and Perugini stress the importance of engaging experienced and reputable financing partners early. Developers and EPCs should seek indicative PPA pricing to gauge customer interest, then work with financiers to firm up deal parameters and responsibilities, including project diligence and financing requirements. Detailed project modeling and a competitive process can take a few weeks. But they help all parties align from the start, prevent miscommunication, and avoid surprises later on.

For solar developers and installers new to PPAs, the experts also emphasized taking advantage of available modeling tools to assess project viability and listening to customer priorities for cues about financing preferences. Many customers benefit from an informed walk through of purchase and PPA alternatives.

Solar PPA Project Lifecycle (Graphic: Conductor Solar)

2023 was a banner year for C&I solar, with the segment installing 1.8 GW according to Wood Mackenzie and SEIA, up 19% from 2022 and the most since 2017. California led the pack, accounting for 35% of C&I deployment and doubling its typical installation volumes in Q4 as projects raced to lock in favorable net metering rates before switching to a new regime. Looking ahead, C&I solar is poised for continued expansion. Wood Mackenzie forecasts 12% average annual growth through 2028 as improving economics, corporate clean energy goals, and policies like tax credits and state-level incentives support demand.

As the C&I solar market expands, partnerships and platforms like Conductor Solar can help developers efficiently source PPA financing and benchmarking, streamlining the path to completed projects. With the right approach, PPAs offer an attractive way to bring more clean energy online while delivering tangible economic and environmental benefits for all stakeholders involved.

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Advancements in remote measurement can help solar companies to bypass inefficient and error-prone site visits to measure and record roof dimensions, azimuth, pitch, and localized shading at a given site in a more consistent and repeatable manner

A recent Wall Street Journal article calls out that the state of the solar industry is nearing collapse due to high interest rates and less-generous subsidies. That’s part but not all of the issue. The true problem in the industry is the bad or “good enough” data that solar companies use to sell installations. They pull information on shade analysis, sunlight analysis and a particular solar installation’s capacity to create electricity. While that data can look compelling to homeowners, it can backfire for the industry when the use of “good enough” data fails to prove out.

This is a challenge the industry needs to address. Solar systems must be sold with more accurate representations of electrical production, appropriate saving estimations, and clear explanations of how the representations might fluctuate. Similarly, customers should be given benchmarks for how much electricity should be produced in order to determine if their equipment might be faulty (i.e., squirrels could be chewing on wires). If a homeowner is not seeing the electricity production or monthly savings, there is a chance that they might stop making payments but also that will negatively view their solar experience. And, both are detrimental to the industry.

Proper estimates of solar systems save solar companies time and money as well. It’s expensive for solar companies to send repair trucks to review solar panels and for electricians to inspect solar systems particularly when operating across large metropolitan areas. The more that companies can leverage precise site data throughout a project’s sales, planning, installation, and close-out phases, the more profitable they can become. High-quality site measurements will generally result in quicker sales cycles from lead through installation, which can help speed payment and cash flow. On the flip side, inaccurate site measurements may result in less profitable jobs in the best case and potential canceled contracts and lost referrals in the worst.

Everyone loses when the data cannot be trusted. Accurate roof and site data can help enable the design of optimized, high-performance systems that maximize the available roof space. When measurement and site data are more accurately collected, the potential results include not only larger systems, but also can help deliver more significant savings for the homeowner and improved return on investment.

Unfortunately, many contractors use do-it-yourself software tools to design systems, and purposefully underutilize roof space to avoid issues at final design or installation. Undersizing a solar system may help mitigate risk but doing so may often leave money on the table for the contractor, and may negatively impact return on investment for the homeowner.

Advancements in remote measurement can help solar companies to bypass inefficient and error-prone site visits to measure and record roof dimensions, azimuth, pitch, and localized shading at a given site in a more consistent and repeatable manner. This helps homeowners and improves the industry.

Some remote measurement technology, such as aerial imagery, captures thousands of measurement points. The solar access value of a roof measured with a hand-held device typically has 5–10 measurement values per roof. In comparison, the same rooftop solar access value measured with software based on high-resolution aerial imagery generally has 6,000–24,000 measurement values per structure.

High-resolution site measurements can positively impact solar installations across the board. They allow solar companies to fit more modules on the average rooftop and inform designs that utilize optimal roof areas that maximize annual solar energy production.

The future of solar rests on trustworthy data. That data must be gathered, utilized and integrated into solar company workflows to give customers the highest level of accuracy and consistency. Anything less hurts the customer and will destroy the demand for solar adoption at large.

Peter Cleveland is vice president of solar at EagleView, a provider of aerial imagery, geospatial software, and analytics.

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IEA PVPS Task 12 analyzes the environmental impact of passivated emitter and rear cell (PERC) technology in PV installations in comparison to the monocrystalline silicon technology (AI-BSF) and the trend towards installing horizontal single-axis tracker systems as opposed to fixed tilt systems.

From pv magazine Global

In 2022, the global solar photovoltaic (PV) generation experienced an unprecedented surge, marking a record increase of 270 TWh and reaching nearly 1 200 TWh worldwide. This remarkable growth underscores the pivotal role of solar energy in meeting the escalating global electricity demand while simultaneously mitigating greenhouse gas emissions. The driving force behind this was the establishment of new manufacturing capacities, alongside the transition from aluminum-back surface field (Al-BSF) cell technology to the more advanced passivated emitter and rear cell (PERC) technology around 10 years ago. The emergence of PERC as the standard technology is marked by its distinguishing features: an additional dielectric passivation stack on the rear of the cell and its possible bifaciality. This technology has replaced older cell structures like Al-BSF, primarily due to its improved efficiency gains in both PV cells and modules, leading to an increase in the nameplate power of modules. Moreover, there has been a notable rise in the adoption of Horizontal Single Axis Tracker systems, which offer higher kWh production per kW installed compared to fixed-tilt systems across various geographical locations. This shift towards more efficient and productive PV systems underscores a commitment to sustainable energy solutions.

Environmental Impact Assessment

While the energy production aspects of PV technologies have been extensively studied, a comprehensive understanding of their environmental footprint is essential. IEA PVPS Task 12 Experts have been employing their life cycle assessment (LCA) methodology to evaluate the environmental impacts associated with PERC technology in comparison to AI-BSF technology. By utilizing primary data from an Italian manufacturer, the report “Environmental Life Cycle Assessment of Passivated Emitter and Rear Contact (PERC) Photovoltaic Module Technology” provides an in-depth analysis of the complete life cycle of PV systems, encompassing manufacturing, installation, operation, and end-of-life phases. While based on analysis of data from only one manufacturer, the findings suggest that the transition from Al-BSF to PERC technology results in significant reductions in greenhouse gas emissions, energy consumption, and resource depletion throughout the life cycle of PV systems.

“The main thrust of our report is to analyze the impacts of the dominant technology in photovoltaics, using the LCA methodology and incorporating primary and up-to-date data,” Pierpaolo Girardi, co-Author of the report said. “This approach allows us to assert that electricity generated by PERC technology manufactured by an Italian company has a carbon footprint lower by 15% compared to electricity production with the currently most installed photovoltaic technology (Al BSF), and a 96% reduction compared to electricity produced by a typical Italian natural gas combined cycle power plant.”

Life Cycle Assessment Methodology

LCA is a structured, comprehensive method of quantifying material- and energy-flows and their associated emissions caused in the life cycle of goods and services. The ISO 14040 and 14044 standards provide the framework for LCA. IEA PVPS Task 12 subsequently developed guidelines, now in their 4th edition, to provide guidance on assuring consistency, balance, and quality to enhance the credibility and reliability of the results from LCAs on photovoltaic (PV) electricity generation systems.

Unveiling the Environmental Footprint

In their report, the Task 12 experts analyze two possible designs: (1) modules mounted on a horizontal single-axis tracker and (2) modules installed on a fixed structure. In addition, two possible PV locations with different irradiance levels are considered: one in the north of Italy and the other in the south of Italy; results shown here represent those for Southern Italy. The results, based on primary data from one manufacturer, are impressive:

1. Greenhouse Gas Emissions: Transitioning from Al-BSF to PERC technology can lead to a reduction in greenhouse gas emissions per kWh produced across both locations. The additional passivation layer in PERC cells enhances energy conversion efficiency, thereby reducing the carbon intensity of electricity generation. Furthermore, the adoption of single-axis solar tracker systems amplifies this environmental benefit, as the increased energy yield per kW installed translates into lower emissions per unit of electricity produced.

The new IEA PVPS Task 12 report analyzes in detail the greenhouse gas emissions associated with using the PERC technology (see Fig. 1 for an example)

Figure 1: Greenhouse gas emissions of a PERC Power Plant in the south of ItalyImage: IEA-PVPSThe PERC PV plant located in the south of Italy is responsible for 17 g of CO2 equivalent per kWh produced. This figure illustrates the contribution analysis of the PERC PV plant based on primary data from an Italian PERC manufacturer. The percentages represent the contribution associated with each component/process. Note also that the tracking system is based on primary data from a manufacturer. The process/component highlighted in blue is associated with module production, which – from raw material to module assembly – accounts for 79% of the total life cycle of the plant.

When comparing the PERC PV plant to a typical Italian natural gas power plant (which accounts for about 50% of the Italian energy mix), the significant difference in greenhouse gas emissions becomes obvious (see Fig. 2). The comparison is made in terms of grams of CO2 equivalent emitted per kWh produced by each plant.

Figure 2: Comparison of greenhouse gas emissions between different types of plants

Figure 2: Comparison of greenhouse gas emissions between different types of plantsImage: Cavalho et al., 20221. Energy Consumption: Similarly, the shift to PERC technology is accompanied by a notable decrease in total energy consumption throughout the life cycle of PV systems. Improved cell efficiency and manufacturing processes contribute to this reduction, underscoring the importance of technological innovation in driving sustainability gains. Moreover, horizontal single-axis tracker systems exhibit higher energy yields per unit of land area, further optimizing energy production and minimizing energy consumption per kWh generated. Note also that the LCA of the tracking system is based on primary data from a manufacturer. 2. Resource Depletion: While both Al-BSF and PERC technologies rely on a similar suite of materials, the efficiency improvements associated with PERC cells mitigate resource depletion impacts. By maximizing energy output per unit of material input, PERC technology minimizes the extraction and utilization of finite resources, thereby alleviating pressure on critical minerals and metals.

Paving the Path to Sustainable Solar Energy

The study highlights the potential environmental benefits of PERC technology. Based on the results of this case study of one PERC manufacturer, by utilizing PERC, the solar industry can reduce greenhouse gas emissions, energy consumption, and resource depletion, while simultaneously increasing energy yields. Additionally, the analysis of different mounting systems reveals that modules mounted on a horizontal single-axis tracker can lead to preferable environmental outcomes, especially in latitudes similar to those in Italy. Furthermore, a sensitivity analysis included in the Task 12 report suggests that extending the lifetime of PV panels can lower specific environmental impacts per kWh, emphasizing the importance of longevity in panel performance.

Moving forward, concerted efforts to promote the adoption of environmentally responsible technologies and optimize site selection can increase the realization of the full potential of solar energy as a cornerstone of the clean energy transition.

Download the full report here.

For more information on IEA PVPS Task 12 and Sustainability of PV Systems please click here.

This article is part of a monthly column by the IEA PVPS program. It was contributed by IEA PVPS Task 12 – PV Sustainability.

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As necessary materials from outside China remain scarce, producers struggle to meet UFLPA compliance.

For many organizations, success comes as a result of balancing higher ideals with practical actions. Solar energy has always been held up as the ideal source of green, renewable energy and a way forward from our fossil fuel-reliant ways. It took a while for the practical side of things to catch up to that ideal—the technology was still improving and equipment was not cost-effective enough for wider adoption—but recent years have seen solar energy entering the conversation in a way that we’ve hoped it would for decades.

The production of solar energy equipment has cast shadows in recent years, though. There have been allegations that materials produced or mined with forced labor are often found in solar production supply chains. This is because the vast majority of polysilicon production, crucial to solar panel builds, comes from China. Much of China’s production of this material happens in the Xinjiang Uygur Autonomous Region (XUAR) region which is reportedly rife with modern slavery abuses.

Solar production isn’t the only industry that imports heavily from China and might find themselves bringing materials made by forced labor to U.S. shores—textiles and apparel shipments are also often in question, as the Xinjiang region produces an inordinate amount of the world’s cotton. To improve transparency and prevent materials made with forced labor from entering the country, the United States has implemented the Uyghur Forced Labor Prevention Act (UFLPA).

UFLPA requirements

Solar energy equipment manufacturers are no strangers to complex, multi-step supply chains that can span countries. Unfortunately, the more complex a supply chain is, the more work needs to be done to stay compliant with UFLPA, which in essence is there to require that companies do not import any materials tied to forced labor in the XUAR.

It’s not enough to claim there’s no tie between a company’s polysilicon imports and forced labor, though—the UFLPA wouldn’t be very effective if that’s all it took to comply. On the contrary, the numbers the U.S. Customs and Border Protection (CBP) publishes on its own site show it being aggressively enforced, with nearly $2 billion in goods delayed between June 2022 and the end of 2023 alone as shipments were held for closer inspection. About half of those shipments were denied entry.

Solar companies importing key components for their production have to prove their shipments don’t trace their origins to forced labor and demonstrate their efforts to keep such materials from their shipments.

In practice, the UFLPA looks for a handful of things. Officials will want to see the origin of the materials in any shipment, so a clear audit trail that can be furnished in the form of invoices and detailed production processes is important for solar companies to have available. These companies should also seek to gain transparency into the organizational structure and affiliations of their suppliers and sub-suppliers.

Certain suppliers have clear red flags that appear when one digs into them, such as affiliation with any entity listed on the UFLPA Entity List. Catching those early will allow solar companies to divest from those risky suppliers quickly— again documenting the process wherein suppliers with ties to forced labor are removed from the supply chain will help with compliance. A thorough outline of due diligence procedures, stated goals around ethical sourcing, and any other related initiatives taken may be required by CBP officials.

Since many raw materials crucial to the production of panels are frequently brought over from China, and the non-Chinese supply of these materials is so low, forgoing Chinese-based imports overall is often not an option. Chinese materials are, at least for now, often a necessary component. The question then becomes how to enable the above capabilities to determine which Chinese suppliers utilize forced labor farther upstream, and would put any company importing from them in violation of the UFLPA, and which do not.

Meeting compliance requirements

Gathering, organizing, managing, and reporting such detailed information on suppliers is a significant challenge for any company. Solar production companies can tap into recent automation innovations within their third-party management processes to survey current suppliers (and their own suppliers) and monitor their entire supply chain for potential risks of UFLPA violation.

Underlying the UFLPA’s requirement for transparency is the need to access, store, and report crucial documentation. With large and complex supply chains, this requires a detailed supplier map to be built. Such a map can lay out the dependencies and connections between entities, which helps in laying out a path forward when a potential violation is uncovered. If a supplier is found to be sourcing materials from another supplier who has been flagged for violations in the past, an automated system could flag that company to supply chain managers and show all the parts of the supply chain that are at risk of a UFLPA violation as a result. Solar companies should be sure to build out escalation procedures and mitigation strategies for such a situation beforehand so that the options available to fix the situation are clear and actionable.

Automation can also routinely monitor the ownership structure of suppliers to track any changes that might bring a previously green-lit supplier into violation. Ownership structures and corporate relationships change all the time; manual review of every corner of a vast supply chain is impractical and costly.

Overenforcement by the CBP could still hit even the most compliant of companies and delay shipments—since half of the held shipments in the example period above were ultimately denied, that means the other half were fully compliant but still were held up for weeks or even longer. But clear documentation available up front might help a company keep their shipments out of a detainment scenario.

And of course, the benefits of staying compliant are well worth it. Beyond avoiding a situation wherein a company’s imports are held up or even refused, the companies that are demonstrating adherence to the UFLPA can more easily pivot to higher-margin markets thanks to transparency in their ethical sourcing practices. And of course, there’s the worldwide benefit of the entire industry being encouraged to source ethically and stop funding those utilizing forced labor. If we’re going to put an end to forced labor around the world, adhering as an industry to regulations like the UFLPA is one of the key steps toward doing so.

Toward a brighter tomorrow

Many other worldwide bodies are considering similar legislation to combat forced labor, and we’ve recently seen actions taken in the European Union with this goal in mind. The consensus seems to be that detailed regulations and careful enforcement are the way forward as we look to put forced labor behind us as a global society.

With the solar industry’s inherent forward-looking and ethical nature, there is the potential for solar companies to play a leading role in shaping yet another aspect of the future, beyond the push for clean and renewable energy. A sustainable world that does not make room for human rights abuses can serve as a model for how to move beyond such practices—the international collaboration required to fully root our forced labor in the solar industry could be replicated elsewhere, ushering in not just a brighter, but a more humane future for all.

Jag Lambda is the founder and CEO of Certa, a third-party lifecycle management platform for procurement, compliance, and ESG. Certa is backed by Techstars and top global VCs. A Wharton and McKinsey alum, Jag lives in California, and loves hiking and playing soccer with his son.

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Aerial imagery provides location intelligence, offering detailed insights that reveal everything from subtle shading patterns to potential obstacles, empowering engineers to design solar farms with laser-sharp precision.

Gone are the days of relying solely on ground-level surveys. Today, high-resolution photographs and 3D models generated from aerial imagery paint a comprehensive picture of any given piece of land.

Location intelligence—the process of deriving meaningful insights from geospatial data—and aerial imagery are becoming more prominent in the solar industry. These tools are reshaping the solar power landscape, enabling developers to identify the best areas and layout for solar farms, as well as the optimal tilt of solar panels for increased sun exposure. These changes are not only bringing efficiency upgrades; they are paving the way for timely and relevant solutions to address ongoing climate issues that promise to propel the U.S. toward a more sustainable future.

Tech-driven solar solutions

In 2023, solar energy represented over half of all new electricity-generating capacity added to the U.S. grid, underscoring a strong societal shift towards renewable energy. The proliferation of solar energy projects benefits from advancements in aerial imagery technology and location intelligence, as aerial imagery offers a clear and comprehensive view from above. From these images, engineers can glean up-to-date information about the landscape and measure key areas remotely, enabling them to minimize costly and time-consuming on-site visits for peak efficiency.

Location intelligence provides detailed insights that reveal everything from subtle shading patterns to potential obstacles, empowering engineers to design solar farms with laser-sharp precision. This meticulous planning ensures optimal panel positioning, maximizing energy capture and ensuring every sunbeam is harnessed effectively.

And beyond efficiency, location intelligence aids in the integration of solar farms into local landscapes and communities, minimizing visual impact and fostering coexistence with residents. Solar farms, supported by local buy-in and the insightful application of technology, are set to become an integral part of the U.S. energy landscape.

Sustainability implications

Greater access to increasingly sophisticated aerial imagery and location intelligence technology can also help U.S. communities produce clean(er) energy and minimize carbon footprints to achieve sustainability goals. These tools are crucial in the solar panel installation process, as they help in identifying the communities and infrastructure that are most suitable for solar panel deployment.

Though solar farms are largely located in rural areas, increasing use and accuracy of location intelligence and aerial imagery technology is also helping cities become more sustainable. Picture this: Sleek, solar-powered facades seamlessly integrated into the design of skyscrapers, transforming them into self-sufficient powerhouses. These very advancements are happening today with the support of location intelligence.

For example, a rapidly evolving technology, building integrated photovoltaics (BIPV) is a material that, as the name implies, is integrated into the building either on new construction or retrofitted after construction is complete. First emerging in the 1970s as aluminum-framed photovoltaic modules, these building-integrated features now take the form of roof tiles, siding or windows that draw in solar rays and convert them directly into energy for the building.

And by analyzing detailed 3D models of buildings generated from aerial data, architects and engineers can then design and install custom-fit BIPV systems to complement the structure’s shape, orientation and energy needs. This ensures optimal energy capture while preserving aesthetics. Moreover, aerial imagery helps map potential shading obstacles like trees or neighboring buildings, allowing for adjustments in the BIPV design to maximize sunlight exposure. The result is stunning buildings that generate their own clean energy, reducing reliance on traditional power sources and contributing to a more eco-conscious society.

Innovative solutions

Location intelligence and aerial imagery technology have set a new standard for a world powered by sunlight, where innovation and environmental responsibility go hand in hand. As insights derived from aerial imagery become more accessible, the deployment of additional solar infrastructure, optimal panel placement, enhanced energy generation and project return on investment become a reality. Government officials and developers that effectively leverage aerial imagery and location intelligence insights are well-prepared to build a brighter future.

Shelly Carroll is vice president and general manager of Nearmap, a location intelligence and aerial imagery solutions provider.

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The Middle Island Solar Farm stands today as a beacon of innovation and sustainability after public perception, outdated zoning laws and bureaucratic red tape presented significant hurdles to its development.

As a serial entrepreneur and advocate for environmental stewardship, I’ve navigated the complexities of various industries, but few have been as challenging – or as rewarding – as the journey to establish a solar farm on Long Island; New York.

The Middle Island Solar Farm (MISF) stands today as a beacon of innovation and sustainability. Since its full operation in 2018, MISF has been generating 19.6 MW of electricity, equivalent to powering approximately 4,000 homes annually on Long Island.

Moreover, its clean energy output translates to removing the emissions of 6,000-8,000 cars from our roadways, a significant stride towards environmental sustainability. Witnessing the realization of my vision to utilize private investment for public welfare brings me immense satisfaction. However, the road to its success was fraught with obstacles that threatened to derail the project at every turn.

One of the most pervasive challenges we encountered was the Not In My Backyard (NIMBY) mindset prevalent in many communities. Despite the undeniable benefits of solar energy – including reduced carbon emissions and energy independence – local opposition often arises, fueled by fear and misinformation. Overcoming this resistance requires patience, perseverance, and a commitment to community engagement.

In addition to public perception, outdated zoning laws and bureaucratic red tape presented significant hurdles to the development of MISF. The arbitrary classification of solar farms as electric generating plants, coupled with convoluted regulatory processes, created unnecessary delays and added complexity to the approval process. Reforming these outdated laws and streamlining regulatory procedures are essential steps towards facilitating the growth of the renewable energy sector.

Furthermore, the influence of vested interests cannot be ignored. Established industries, threatened by the rise of sustainable energy, have wielded considerable power and resources to maintain the status quo. Lobbying efforts aimed at undermining clean energy initiatives perpetuate dependence on fossil fuels, hindering progress towards a greener future.

Despite these challenges, the case for clean energy investment remains stronger than ever. The economic and environmental benefits of renewable energy are undeniable, with solar power emerging as a viable alternative to traditional energy sources. However, realizing this potential requires a concerted effort to dismantle systemic barriers and create a more conducive environment for investment.

Education and community engagement are crucial components of this effort. By dispelling myths and highlighting the tangible benefits of clean energy projects, we can garner public support and overcome opposition. Moreover, fostering partnerships between government agencies, businesses, and local communities can help streamline the approval process and expedite the development of renewable energy infrastructure.

Additionally, policymakers must prioritize sustainability and incentivize investment in clean energy initiatives. By implementing policies that promote renewable energy adoption and phase out subsidies for fossil fuels, we can level the playing field and create a more equitable energy landscape.

As we confront the urgent challenges of climate change and environmental degradation, the need for decisive action has never been greater. By breaking down barriers to clean energy investment, we can pave the way for a brighter, more sustainable future for generations to come. It’s time to harness the power of innovation and collective action to build a world powered by clean, renewable energy. The time for change is now.

Jerry Rosengarten is a serial entrepreneur and advocate for environmental stewardship. He is the author of Jump on the Train: A Dyslexic Entrepreneur’s 50-Year Ride From The Leisure Suit to the Bowery Hotel and a New York Solar Farm.

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Part four of Dan Shugar’s series on replacing fiction with facts about solar, when the proverbial Uncle Bob comes to dinner.

‘Uncle Bob’ is that proverbial character who shares at family gatherings all he believes to be true about solar and why it just isn’t a good idea. Dan Shugar, founder and CEO of Nextracker, has had this experience. Based on his 33 years in the solar industry, he offers short, fact-based responses to Uncle Bob’s assertions, which range from “solar is taking coal jobs” to “solar is unreliable.”

In this part four of the series, Shugar debunks myths about solar using too much land.

The proverbial Uncle Bob asks, “What about all that land being used by solar, if we try to power the country with solar, the whole country is going to be covered with solar panels.”

You could say, listen Uncle Bob, if we were to power 100%, and I mean generate extra energy in the day so batteries are using their power at night for everything, solar would cover less than one half of 1% of the land area.

But of course, solar is not just on land. It is being put on rooftops on homes or businesses. It covers carports. We see those a lot of solar on schools and for systems that are on the ground, which typically follow the sun with a tracker, we’re seeing customers increasingly use dual-use applications. For example, one of our great customers, Silicon Ranch Corporation, has pioneered the idea of dual use with agriculture and ranching where we’re seeing many solar power plants grazing livestock, sheep, cattle, and pollinators.

There’s plenty of area out there and we’re creating economic value in communities where projects are being built. We’re not manufacturing things in a faraway land and dumping them in communities, but they’re being made in the communities in which they’ll be used.

One of the most gratifying projects we’ve done at Nextracker with our manufacturing partner, J.M. Steel, brought new life to a manufacturing facility in Pittsburgh, Pennsylvania that had previously been a Bethlehem Steel facility, but it had been dormant for many decades. In fact, at that exact facility they made landing aircraft that were used to support the Normandy landing in World War Two. But we were able to use that existing technology with steel conveyors and equipment and infrastructure to start making modern solar plants. So, we’ve been able to create a new ecosystem.

It’s the ground zero of the new industrial revolution in clean energy.

Episode four: What about all that land being used by solar?

We’ll continue this series with fact-based responses to additional myths such as “solar takes too many coal jobs”.

Stay tuned as we unpack these objections, so you’re ready for your next dinner party with Uncle Bob.

View earlier episodes:

• Part one, “All panels come from China” here.
• Part two, “Solar is unreliable” here.
• Part three, “What about nuclear?” here.

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In a new weekly update for pv magazine, Solcast, a DNV company, reports that persistent high pressure in the upper atmosphere led to irradiance as high as 30% above normal, and new records for solar generation and temperature in North America in mid-February.

From pv magazine global

A warm end to winter hit most of North America this February. In the west, during February mild air from the Pacific banked up clouds and depressed irradiance by 10-20%, according to analysis completed using the Solcast API. In the east, persistent high pressure in the upper atmosphere led to irradiance as high as 30% above normal, and new records for solar generation and temperature.

A clear east/west divide is present in the irradiance anomaly this month. A strong low pressure system sat further east than normal over the Atlantic which brought calm, drier and sunny conditions to the Eastern U.S. and Mexico. Sunnier than normal conditions delivered 20-30% more irradiance than normal from Texas to New England. On the west coast however, high pressure was further west over the Pacific, so that coastal low pressure systems pulled moist air from equatorial regions, leading to increased clouds, blocking irradiance.

Clear skies and higher than normal irradiance will have benefited both large and small scale, solar producers. Residential ‘behind the meter’ solar performed strongly this February all over the East Coast. Solcast’s Grid Aggregation model for NYISO shows residential solar peaked at 3.52GW, and saw 23% more solar generation than last year after adjusting for capacity increases. By contrast, CAISO’s residential solar generation was down 12% on the long term capacity-adjusted average.

Utility-scale generation in ERCOT also hit and surpassed their generation peak record, hitting 17.2GW on February 20th. A 50.1% increase in peak generation in February 2023, is mostly a function of capacity increases in the last year.

But it wasn’t just grid performance breaking recent records, temperature records were broken across the country, with the average temperature, more than 4 degrees above normal. Killeen in Texas saw a peak temperature of 38 C (100 F), and Jacaranda trees in Mexico City have been in full bloom all month, 6-8 weeks earlier than normal. Despite the heat further south, areas in Eastern Canada saw significant snowfall caused by a low pressure system stalling over the area, drawing in continuous cold air from the Atlantic. This caused one of the heaviest snowfall events in 20 years, blanketing parts of Nova Scotia with more than a meter of snow.

This extreme weather is reflective of an overall pattern being seen globally, as February 2024 was Earth’s warmest month on record for the 9th consecutive month.

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.

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Part three of Dan Shugar’s series on replacing fiction with facts about solar, when the proverbial Uncle Bob comes to dinner.

‘Uncle Bob’ is that proverbial character who shares at family gatherings all he believes to be true about solar and why it just isn’t a good idea. Dan Shugar, founder and CEO of Nextracker, has had this experience. Based on his 33 years in the solar industry, he offers short, fact-based responses to Uncle Bob’s assertions, which range from “solar is taking coal jobs” to “solar is unreliable”.

In this part three of the series, Shugar debunks myths about nuclear energy.

The proverbial Uncle Bob asks, “What about nuclear? That’s reliable runs all the time. Why don’t we do more of that?”

You could say, “Listen, Uncle Bob, there are things we like about nuclear. We know you don’t believe in global warming. But we like that nuclear is a zero-carbon option.”

Then explain that there are only two problems with nuclear. First, there’s radioactive waste, and second, it’s too expensive.

Let’s ignore the radioactive waste that is around for hundreds of years. Let’s talk about money.

A new nuclear plant today is about $180 a megawatt hour. A new solar plant today is $60 a megawatt hour. That’s about a third of the cost. And if you add batteries, it’s about $75 a megawatt hour. That’s well under half the cost rather than dollars per megawatt hour.

Now let’s just talk about money of real plants. When I started in my career, in 1985, the Diablo Canyon Nuclear Power Plant was just finishing the original budget of that plant was $380 million. And the plant was actually completed at five and a half billion dollars, half of PG&E’s net income was being absorbed by the interests of the plant.

In more modern history, the two Vogtle units, one of which is operational in Georgia and the other is supposed to come on online shortly, were under construction for over 10 years and had an original budget of about $14 billion. They came in at about $30 billion, which is very expensive.

Speaking as an environmentalist, I really hope nuclear can have a resurgence, including the modular nuclear power plant designs that have been under development for decades. But I want to underscore the bar keeps going up because solar and wind costs are going down. While reliability keeps improving nuclear power is just too expensive Uncle Bob.

Episode three: What about nuclear?…

We’ll continue this series with fact-based responses to additional myths such as: Solar takes too much land–there’s gonna be no room for farms if we have solar panels…

Stay tuned as we unpack these objections, so you’re ready for your next dinner party with Uncle Bob.

View earlier episodes:

Part one, “All panels come from China” here.
Part two, “Solar is unreliable” here.

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In a new weekly update for pv magazine, OPIS, a Dow Jones company, provides a quick look at the main price trends in the global PV industry.

From pv magazine global

The Chinese Module Marker (CMM), the OPIS benchmark assessment for mono PERC modules from China was assessed at $0.110 per W, stable from the previous week while TOPCon module prices were flat at $0.119/W week to week. Prices have held steady for the seventh consecutive week as market participants adopt a wait-and-see approach for a clearer price trend to emerge.

Market sentiment was mixed. There were some talks in the market of possible domestic Chinese price increases of CNY0.03-0.05 ($0.042-0.069)/W in March but other market participants were uncertain if the price hikes would materialize given ample inventory in the market.

Other market participants attributed the possible price hikes to suppliers’ reluctance to accept orders at previously lower prices and the fast conversion of p-type to n-type in the market had resulted in a drop in P-type supply. “Cell makers had increased P-type prices before the Lunar New Year but did not increase n-type prices”, a market source said.

One seller held on to the view that any price increases in the Chinese market would be for p-type modules as production had reduced and that N-type modules could see some price declines. However, other market participants said this remains to be seen.

The outlook for March was improving with demand expected to recover in Q2-Q3 as overseas projects usually start construction after winter, while in China, module tenders are generally carried out in the first half of the year and construction in the second half of the year, a solar veteran said. The Chinese market will see 30-40% of demand in the first half of the year, with most of the demand concentrated in the second half of the year, the veteran added.

Module makers are expected to increase their operating rates as demand improves in the coming weeks. China is expected to produce more than 50 GW of modules in March, according to the Silicon Industry of China Nonferrous Metals Industry Association.

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.

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How to play in the sandbox: Understanding the interplay of the mineral estate and the surface estate and strategies for successful surface project development in Texas, California and elsewhere.

Texas and California lead the country in terms of solar energy generating capacity, while also maintaining major oil and gas production operations, which demonstrates that it is possible for these uses to successfully coexist, even if doing so can be complicated.

As solar energy projects cover almost the entire surface of the land that they utilize with solar panels, it is necessary to understand the rights of the mineral estate holders to utilize the surface, especially in areas with historical and current oil and gas production.. Any compatibility issues with the mineral estate holder(s) need to be addressed before a solar energy project can be constructed and financed.

Understanding the rights of the subsurface estate

When the mineral and surface estates are held separately in Texas, the subsurface owner has a right to use as much of the surface as is reasonably necessary to produce and remove the oil, gas and/or minerals below the surface. Similarly, in California, mineral estate owners are permitted to use the surface as is necessary and convenient to produce and remove the oil, gas and/or minerals below the surface. However, mineral estate owners in both states are generally not permitted to impose a greater burden on the surface estate than reasonably necessary for the mineral estate owner to fully exercise their rights. These standards have proved difficult to interpret and apply with predictability in practice, which causes uncertainty about how a surface owner’s and subsurface owner’s rights might intersect in a specific situation.

For any solar energy project, the solar developer must understand: (1) whether the mineral estate has been severed and who holds title, (2) the magnitude and nature of the risks related to possible surface use by the mineral estate and, (3) if there are risks, how to reduce those risks and/or obtain title insurance satisfactory to insure against the risk of forced removal of solar facilities.

Determining rights in the subsurface estate

Title companies will provide information and insurance for the ownership of the surface estate, but generally will not provide vesting information or insurance for the subsurface/mineral estate. Accordingly, project developers typically have to look to a “landman” to search the real property records to establish ownership of the mineral estate underlying the solar project lands.

Landmen, sometimes in conjunction with legal counsel, can help project developers obtain surface waiver agreements, surface use and/or accommodation agreements, and mineral estate purchase agreements to help procure a financeable project site with sufficiently secure surface rights.

Surface waiver and accommodation agreements

An effective surface rights waiver will prohibit the mineral interest holder, and its successors and assigns, from disturbing the surface of the solar project site. When possible, surface rights waivers should be absolute, waiving all rights of the mineral owner to use the surface of the property—including for exploration, testing, and general access—not just production. In addition, it should waive the right to use the surface to access any mineral or subsurface material, not just oil and gas. In order to fully bind sublessees, successors, and future grantees, a waiver of surface rights must also be recorded in the real property records.

When a mineral estate owner is unwilling to entirely waive its rights to the surface of the property, an alternative is to utilize an accommodation agreement that (1) sets aside certain areas on the property which are reserved for oil, gas and minerals activities, (2) includes a surface waiver from the mineral estate holder for the benefit of the surface owner on the remainder of the property, and (3) contains other agreements designed to allow the parties to share the use of the surface estate.

Alternatives to surface waivers or accommodation agreements

Ideally, a developer should obtain surface waivers or accommodation agreements from 100% of the mineral interest holders, but if this is not possible, a project developer should not despair. Many oil and gas producers are unwilling to take mineral leases or develop minerals based on a lease from only a small, fractional mineral owner. As a result, it is often sufficient to obtain surface waivers or accommodation agreements from less than 100% of the mineral interest holders. While there is no established standard agreed to by title companies and attorneys in the industry as to what percentage of the mineral interest surface waivers is required to be sufficient, it is universally agreed that sufficient does not mean 100%. In this situation, the developer may also pursue other strategies to ensure that it holds secure rights to the surface of the project site and obtain the title insurance it needs.

1. Review Regulatory Restrictions. Regulatory or property/locational specific factors, like zoning restrictions, should be reviewed as they may reduce or eliminate the likelihood that mineral estate development will occur on the property.
2. Drill Site Reservations. Another strategy is to proactively set aside reasonable drill site areas, along with access and utilities easement paths to serve the drills sites. The reserved “drill island” areas should be sufficient in number and size to reasonably accommodate the mineral estate holder’s ability to access and exploit the underlying mineral estate and should be designed with the help of a petroleum engineer or other oil and gas expert.
3. Likelihood of Commercially Viable Mineral Production. If the location of a developer’s planned project site is in an area with little or no oil, gas or mineral production historically, the developer may also want to engage a Landman or appropriate consultant to provide a short report summarizing the absence of any commercially viable oil, gas or mineral resources and production in the planned project site area, to provide support for the title company to underwrite the forced removal risk notwithstanding a lack of surface waivers or accommodation agreements.

Title insurance related to mineral rights risk

Title insurance covering the mineral risk issue will be required in order to obtain construction financing for a project. Texas has four different types of promulgated title insurance endorsements to address mineral issues when a title insurance company issues a lender’s or owner’s title policy with an exception or exclusion for mineral estate coverage: Forms T-19, T-19.1, T-19.2 and T-19.3. In California, the ALTA Form 35 endorsements (ALTA 35, 35.1, 35.2, 35.3) are typically used to address mineral issues.

Note also that these endorsements insure against some of the losses that a solar energy project owner or lender may be exposed to related to the mineral estate, such as coverage for the value of the real estate rights and improvements lost if mineral development forces the solar project operator to relocate or remove solar facilities. However, the endorsements don’t provide coverage for the revenues and profits the project may lose as a result of the forced removal, or for project downtime or other business-related aspects of the project. Other forms of commercial insurance may be available to address such risks.

Dirk R. Mueller is a partner and Alyssa Netto is an associate with the law firm Farella Braun + Martel LLP in San Francisco. Will Russ is a partner with the law firm Barnes & Thornburg LLP in Dallas.

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Three strategies to manage and reduce project costs, access new talent pools and upskill workers, and positively influence public opinion about the worth of these projects.

The adoption of solar energy in the United States is increasing, and with it, the opportunity for notable market expansion for the companies and field services teams that site, install and service these projects.

Spurred by growing business and consumer demand for clean electricity, technology advances, and favorable federal and state policies, 63 GW of new utility-scale solar power generation is expected this year, adding significantly more than the 40 GW added in 2023. However, solar energy accounts for just 3.4% of all U.S. electricity generation, meaning there is room for significant expansion.

Customers now have multiple options to choose from when deciding how they deploy and use solar power. Large businesses can integrate solar power with battery energy storage systems, capturing, storing, and flexibly deploying this green power source as needed. Advances such as transparent solar panels and thin-film technology also promise to make solar energy more suitable for various business and consumer applications.

Despite these promising trends, challenges stand in the way of boosting solar adoption. High costs, unskilled or inaccessible labor, and negative public sentiment could prevent solar from growing at the rates predicted.

• Solar costs are slowing growth: Installation costs are a vital concern for cities, commercial and residential developers, and landowners who approve these projects. Deploying utility-scale solar installations ranges from $16/MWh to $35 MWh —comparable with other energy forms used to generate electricity. However, as any student of renewables knows, solar typically adds to, rather than replaces, traditional energy sources because of its intermittent nature. So, these costs are additive to overall energy investments rather than subtractive for project owners. In addition, deploying solar power requires specialized labor, including project developers, energy analysts, solar and electrical engineers, electricians, project managers, operations and maintenance technicians, thermal engineers, and software developers. As a result, labor costs are estimated to constitute 7% of a project’s total price.
• Project owners have difficulty accessing skilled labor: The rapid growth of the solar industry is outpacing workforce availability and skills. While the U.S. Inflation Reduction Act will create 100,000 new clean energy jobs, solar project developers will likely be hard-pressed to fill them. In addition, current workers will need to be upskilled on new technologies and processes.
• Navigating negative public opinion: Corporate solar energy adoption has grown steadily over the past few years, accounting for nearly half of all new deployments since 2020. However, consumers and other business leaders may believe solar energy is expensive, doesn’t provide immediate results, requires extensive maintenance, and can be easily damaged.

The good news is that there are strategies to address these issues to grow solar energy adoption and accelerate the country’s transition to green energy.

Strategy 1: Deploying technological solutions to manage solar energy cost challenges

The average cost to deploy solar panels residentially has been estimated at around $25k, but final costs vary depending on panel type and model; auxiliary equipment costs; and federal or state incentives. In addition, homeowners need to budget for ongoing system maintenance, cleaning, and repair.

Technology can improve solar power efficiency and performance. Internet-enabled sensors on solar panels and components provide a continuous stream of data on the system’s energy production levels, temperature and efficiency. Then, artificial intelligence (AI) and machine learning (ML) algorithms analyze sensor data, detecting anomalies that could indicate a need for proactive or predictive maintenance.

With intelligent monitoring capabilities, operators can detect problems in real-time, decreasing system risks and operating and maintenance costs.

Strategy 2: Addressing labor challenges in solar energy through technologyA recent survey found that nine in 10 U.S. companies are struggling to find the skilled labor forces they need, and job growth continues to outpace the existing talent base.

Solar development companies can use technology to help bridge this gap in several ways. These firms can use tools, such as generative AI copilots, knowledge bases, and web and mobile field services apps to train workers on the latest technologies, methodologies and practices. Workers leverage intuitive interfaces and natural-language queries to learn about new processes, such as implementing new technology or using intelligent monitoring systems.

In addition, workers can use data analytics and AI-powered systems to plan projects, optimize task performance and chart progress. Field service software streamlines projects, from managing work orders; to scheduling, dispatching, and monitoring their workforces; to estimating and invoicing. This integrated functionality helps companies optimize task assignments based on skills and location and ensure that projects are completed promptly and efficiently.

Solar development companies can also use these tools to tap gig workers for assignments, gaining access to an on-demand talent pool and filling skills gaps as needed.

Strategy 3: Shaping public opinion on solar energy through tech-enabled transparency and engagement

Utility-scale solar and wind projects are facing increased headwinds. In Michigan, community members have blocked more than two dozen large-scale projects, while across the U.S., 35 states have implemented 228 restrictions to do likewise.

Solar development companies can leverage field service software to help foster positive public sentiment about solar energy by increasing transparency about planned projects. They can provide real-time data and operational insights about planned projects, building community trust that they will proceed as promised. With this strategy, they can help educate the public about how solar energy works and the benefits it will provide to their communities.

Field service technology

With the recent passage of the Inflation Reduction Act, solar credits for qualifying projects have soared to 30%, providing a compelling reason for businesses and consumers to adopt this technology.

Solar development companies can cash in on this boom by using field service technology to manage and reduce project costs, access new talent pools and upskill workers, and positively influence public opinion about the worth of these projects. Companies that adopt all three strategies and use field service technology can win new projects, manage them to successful completion, and scale their businesses.

Raghav Gurumani is CTO & Co-Founder, Zuper, a specialist in field service management software.

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In a weekly update for pv magazine, OPIS, a Dow Jones company, provides a quick look at the main price trends in the global PV industry.

From pv magazine global

Solar cell FOB China prices have stayed unchanged, with not much real trading taking place as price negotiations for orders delivered in March are still ongoing. Mono PERC M10 and G12 cell prices trended flat at $0.0482 per W and $0.0473/W, respectively, while TOPCon M10 cell prices remained constant at $0.0584/W week to week.

According to a market participant, neither the supply nor the demand for cells has changed significantly as of right now. What will be clearer by month-end is the change in operating rates set by cell and module producers, the source added.

A manufacturer that had already sold Mono PERC M10 cells for the high price of CNY0.4 ($0.056)/W prior to the Lunar New Year said that, although they intend to raise prices even more, their ability to do so will depend on how order talks play out over the next two weeks.

Another source from the cell segment is skeptical about whether cell prices will continue to rise, saying that increases are restrained by the present price and potential future price of modules.

The fact that an increase in end-user demand in 2024 cannot be substantial will weigh on cell prices, according to an upstream insider. “The most bullish forecast I’ve heard so far is that end-user demand would rise by roughly 20% in 2024” compared to 2023, the source added.

Even if prices rise in response to increased demand, only integrated businesses are able to ensure sales volume and profitability, a market observer stated, who went on to say that stand-alone cell producers can only strive for profits by lowering the purchase prices of wafers.

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.

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People, equipment, construction and technology best practices to optimize performance.

As the solar industry matures, pressure for asset owners to deliver higher returns continues to mount. Not surprisingly, so has the demand to improve operations and maintenance (O&M) efficiency – the single largest component of a utility-scale solar asset’s post-construction budget.

Whether an asset owner performs O&M in-house, outsources to a third-party, or utilizes a hybrid mix of the two, getting strategically smart about O&M can substantially boost efficiency. Four strategies to consider are people, equipment, construction and technology.

#1 – People strategy: Know what business you are in

Hiring and retaining competent people is one of the biggest threats that could impede the global transition to clean energy. In 2022, 44% of solar industry employers said it was “very difficult” to find qualified applicants. That’s the highest such percentage ever recorded in the U.S. Interstate Renewable Energy Council (IREC) National Solar Jobs Census. Competition, a small applicant pool, and lack of training and technical skills all contribute to the peril.

With 16,585 reported solar operations and maintenance jobs in the U.S. that’s a hefty challenge, which falls heaviest on asset owners who aren’t technically in the ‘people business’. But O&M service providers are — especially large national players.

It’s complicated. Getting bogged down in the day-to-day of hiring, training and managing talent can be a risky distraction for asset owners, steering their focus away from their number one priority: performance and production of the solar asset. It’s especially challenging when the asset resides in remote, or less desirable locations. Yet, ensuring preventative and corrective maintenance is mission-critical to the asset’s performance. And that requires highly trained people with superior technical and safety skills.

One solution for asset owners is to get out of the people business, and instead leverage resources whose business is people: third-party O&M service providers. For staffing challenges, service providers with a national presence have the ability to pull the right resources to meet immediate needs. And for remote assets, they may already service density in the area, meaning they might already have other assets they operate and maintain nearby.

Outsourcing to a qualified partner alleviates an asset owner’s workforce development headaches too. Becoming a master solar field technician takes years, and with the proliferation of new technologies, the learning curve never stops. While inhouse solar installers may amass years of experience building projects, they are not likely to develop all of the skills needed to become a field technician, much yet to climb the company’s career ladder and move into critical project management roles. Asset owners provide limited opportunities to field technicians requiring specialty electro-mechanical training or mentoring.

Alternatively, O&M service providers are in the business of growing talent at scale. Larger, national firms have invested heavily in workforce development infrastructure – from breaking ground on a multimillion-dollar renewable energy training facility to a mobile university that takes the training right to the job site.

Ensuring that technicians receive vital safety training, certifications, and recertifications needed to comply with OSHA requirements is squarely in the service provider’s wheelhouse as well.

#2 – Equipment strategy: Think O&M first

Solar supply chain issues have been a new-world reality since the pandemic. Even as availability concerns ease, managing panel, inverter, and other equipment inventory to meet preventative and emergency maintenance needs at multiple field sites is a major challenge, especially for owners of large asset portfolios.

Ten different projects could require maintaining inventory from 20 different panel and inverter suppliers – not surprisingly as the projects were likely built by different EPCs who sourced parts from those available at the time. Unfortunately for the asset owner, that adds up 100 different types of parts – or 200+ spares to ensure swift replacements and avoid dreaded and costly downtime. That’s a big challenge for asset owners who maintain their own spare parts inventory. Even if they’ve outsourced to a third-party spare parts provider, they’d face the daunting task of contracting separately for each project.

As the solar industry matures, forward-thinking asset owners are factoring their equipment needs into their O&M strategy. They are standardizing requirements for new projects. When replacing worn out panels and inverters, they contractually require EPCs to source from a short list of preferred manufacturers and OEMs. By leveraging similar equipment across multiple projects, asset owners can allocate capital to make bulk purchases of fewer types of panels and inverters to alleviate spare parts and inventory challenges. Or, if they outsource spare parts inventorying to a third party O&M provider, they can put a master service agreement in place to cover all projects and substantially reduce the time and effort associated with contract negotiations.

Not only does this strategic approach lessen inventory issues for spare parts, it enables asset owners to proactively ensure that their projects are being built with the highest quality components, and optimize procurement pricing in bulk. Training needs diminish too, as technicians are servicing fewer types of equipment. Less equipment variation also results in faster knowledge transfer and more rapid deployment of technicians from one project to another for corrective maintenance or some unforeseen catastrophic issue.

#3 – Construction strategy: Pick two – Fast, cheap, or high quality

Selecting an EPC is one area where the old adage of ‘pick two: fast, cheap, or high quality ’ holds true, especially from an O&M perspective. Fast and cheap have the potential to lead to long-term issues that erode the performance and productivity of an asset, not to mention catastrophic failures.

Choose an EPC with a reputation and history of delivering quality projects on time and on budget. Be sure to have a 100 percent complete site design before entering into the EPC contract. Don’t leave the final details to chance – that’s where panels get installed and where the wiring and cabling takes place and where many O&M nightmare begin.

That’s because some EPCs normally employ a handful of experienced in-house professionals and outsource a lot of the labor to install panels and wiring. When it comes to labor, make sure the EPC isn’t picking cheap over quality.

#4 – Technology strategy: Automate monitoring & data analytics

Condition monitoring is a vital O&M task which requires sifting through and analyzing substantial amounts of data – from power outages to identification of faulty modules, calculation of module efficiency, and compliance to grid standards – to ensure optimal PV system performance.

Traditionally, condition monitoring has been manual and dispersive. Fortunately advancements in condition monitoring automation and data performance analytics are changing that. Today, sophisticated asset owners are turning to remote condition monitoring software to inform their O&M strategies and corrective maintenance plans. Monitoring takes place in remote operations centers – like the Pearce world-class NIRC/CIP Remote Operating Center, designed to meet the North American Electric Reliability Corporation’s (NERC) Critical Infrastructure Protection (CIP) standards. At these centers, performance analytics specialists have a bird’s eye view of multiple production sites at once.

Automated condition monitoring gives Pearce 24×7 visibility into any site’s performance levels, identifying inefficiencies and performing data analysis to pinpoint the root cause of a problem. Analyzing and diagnosing a challenge remotely without sending a technician to the job site to assess the situation helps manage cost. And it accelerates the ability to get a project online faster, significantly reducing downtime.

Condition monitoring systems are making O&M servicing smarter and more efficient. Armed with data about the exact point of failure – whether a dirty filter panel, a faulty PV connecter, or a malfunctioning inverter – the asset owner or their outsourced O&M service provider can deploy a technician with the right knowledge to exactly the right place to resolve the problem faster.

The journey continues

Utility-scale solar has come a long way since the first solar park was built nearly four decades ago. As the industry continues to evolve, O&M best practices and technology will too, paving the way for asset owners to deploy smarter strategies and achieve greater performance.

Daryl Ragsdale is vice president of business development for Pearce Renewables, a national provider of operations, maintenance, and engineering services for mission-critical infrastructure. For more than a decade he has specialized in delivering innovative, simple solutions to solve complex challenges in the wind, battery energy storage, and solar industries.

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While most large-format modules are lab tested for certification, the lab is not the real world. The field loading applied to a solar module depends on the structure on which it is mounted and the terrain of the project.

At the RE+ 2023 conference in Las Vegas, vendors from across the globe displayed their largest, thinnest, bi-facial solar modules, showcasing achievements in photovoltaic cost efficiency. Boasting wattages once unthinkable, the cost reduction juggernaut of solar has marched forward.

For those of us who have designed a solar module and performed mechanical load testing, there is one head-scratching detail that sticks-out and begs for further exploration. These massive modules come equipped with some of the smallest module frames ever seen.

The previously ubiquitous 2- by 1-meter module with a frame height of 50mm is now approximately 55% larger in surface area with frame heights as low as 30mm. How is this possible when mechanical load ratings have remained constant, and the height of a beam is of paramount importance to its strength? Those physics hold true for bridges, buildings, and even the frame of a solar module. Wind and snow loading rise proportionally with the increased surface area, but the latest, longest-ever module frames see a height reduction of ~40%, severely reducing its load-carrying capacity.

Modules are tested to various standard mechanical load tests for certification. These tests apply loads to the front-side and back-side of the module to rate them for withstanding real-world environmental conditions. The current industry standards (UL 61730-2, IEC 61730, IEC 61215-2) all generally agree on mechanical load testing procedures. Many of the modules on the conference floor advertise compliance with these standards and the industry-leading testing labs perform these certification tests with the utmost care and diligence.

While the large-format modules meet these standards in the lab, the lab is not the real-world. The field loading applied to a solar module depends on the structure on which it is mounted and the terrain of the project. The greater the wind zone, the greater the load on the module.

Less obvious is that larger tilt angles typically also increase wind loading on modules and that this varies across locations throughout the array. Picture a ship with its sails raised versus lowered during a storm. Which one has more force to project their vessel forward?

Snow can often have the opposite effect. Panels of a higher tilt angle will often shed more snow than lower tilt panels and thus be more favorable to module loading from snow. Any house roof in a northern latitude will showcase this phenomenon. The project designers must carefully check that the modules selected work with the mounting structure at every location on the project site.

Therefore, to understand the engineering gap at hand, a marriage of large-format module frame design and structural design of racking systems is key. Because module loading is dependent on the supporting structure (e.g., tilt angle, among several variables), structural vendors typically specify expected module loading in project design. Many structural vendors are good at validating that the module itself falls within the certification rating. However, is it possible that some vendors are still missing peak module loads for wind?

Image: Azimuth Advisory Services

A SETO-funded research project being carried out through a joint venture of the Lawrence Berkeley National Lab and UC Berkeley has determined that vendors need to look at smaller effective wind areas than the spans between foundations (not what is shown in Figure 1 A) when estimating individual module loading. PV modules can be broken if attributable areas as small as one-quarter of the module are overloaded (individual fastener level loading – D in Figure 1) and this can be shown to occur at maximum project design conditions for many projects getting installed today. While the evaluation typically carried out is around a maximum design loading, the SETO-funded research team is currently exploring how a lower, uneven cyclical loading can lead to structural failures as well.

If understated peak module wind loading has been common practice in project design for the last 15 years, then module failures should be rampant, no? In practice, older module frames have been pulling double-duty masking this oversight. Some of those module frames were designed with safety factors of 3. Today, large-format modules appear to be designed to safety factors of 1.5 based on reviews of some module manufacturers datasheets and industry standards. This allows the modules to be competitive in the downward march on cost.

When a certification laboratory tests a module to an actual 2,400 Pa of back-side loading, the maximum design pressure it is certified for is 1,600 Pa. It is critical to check if the module rating advertised is what was tested (including safety factors) or if it is what the maximum allowable design pressure is (without safety factors). 1,600 Pa of pressure on a module is approximately equal to a 72-mph wind gust for a module pressure coefficient of 3. The LBNL / UC Berkeley research team has determined that this coefficient is achievable at row ends for module tilts over 15 degrees. This is hardly a sufficient design for any project in the U.S. based on the latest ASCE 7-22 wind maps. If a designer mistakenly used 2,400Pa to be the design pressure, this would increase the allowable wind gust to 88-mph. Thus, it is important to understand what the module rating includes.

Load capacity

The market has driven module load capacity to its breaking point. This seems to be particularly the case regarding backside (wind uplift) loading. Combining legacy engineering assumptions, larger module areas, smaller module frame heights and unclear manufacturer ratings yields a recipe for failures. The goal is not to lay blame, but to understand the technical issues at hand and offer guidance on what stakeholders can do.

Here are tangible ways that developers, financiers, insurance companies, owners, asset managers, structure manufacturers and module manufacturers can manage these risks:

1. Make sure sufficient independent engineer (IE) budget and time is allocated per project (particularly smaller projects) so key details about module loading can be checked not only per project, but at every location on the project (e.g., exterior rows, corners, fasteners).

2. Structure manufacturer due diligence should confirm that:

3. Clip and bolt loads for module retention use “module clip loads” (D in Figure 1) instead of average row areas (A in Figure 1) or even module-level areas (B in Figure 1). See the wind tunnel testing coefficients for more details.

4. Module loading should not be assumed to be the same across the array for wind. The wind loads on modules at the end of the rows are typically higher than those on the interior. This is true for both tracking and fixed tilt systems. [See the latest SEAOC PV2 Wind Design for Loading Arrays]
5. Clip/bolt loading should not be assumed to be the same at each location on the module. Loading on one half of the module is often quite different than the other. The fasteners may end up being the same design, but they should be designed to withstand the highest loading and not a lower average load distributed across the four fasteners.

6. Module rails should be sized accordingly as well, with particular emphasis on exterior module rails and their appropriate rail-level area loading (C in Figure 1) and with assumptions for uneven module loading.

7. Module due diligence should confirm:

8. Whether the module datasheet front-side / back-side mechanical load rating includes the test safety factor (typically 1.5). If it does not, reduce the load rating by the appropriate safety factor and confirm that the structural loading demand does not exceed that new, lower rating based upon the module wind/snow stow angle (tracker) or installation tilt angle (fixed tilt).

9. That the module frame is designed to withstand the extra forces that come with uneven loading for the wind/snow stow angle (tracker) or installation tilt angle (fixed tilt) of the system.
10. The mounting method exactly matches the module certification mounting method and is listed in the module installation manual. If not, the module manufacturer should be requested to issue a letter that the unapproved mounting method will uphold the warranty under the project conditions. Testing may be necessary.

Frank Oudheusden is a manager of Azimuth Advisory Services, a consultancy that provides consulting services to industry leading PV developers, EPC’s, asset managers and racking companies. Oudheusden joined the solar industry in 2008, and prior to consulting, was a senior staff engineer at SunEdison helping to guide the AVL selection of racking systems globally and leading a due diligence team for AVL vendors and M&A activities. Chris Needham is a manager of Azimuth Advisory Services. Needham joined the solar industry in 2007, and prior to consulting, was a senior staff engineer at SunEdison where he designed and developed internal structures including single-axis trackers, fixed tilts, carports and rooftop racking systems. He specializes in wind tunnel testing of PV systems.

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Part One of Dan Shugar’s series on replacing fiction with facts about solar, when the proverbial Uncle Bob comes to dinner.

‘Uncle Bob’ is that proverbial character who shares at family holidays all he believes to be true about solar and why it just isn’t a good idea. Dan Shugar, founder and CEO of Nextracker, has had this experience. Based on his 33 years in the solar industry, he offers short, fact-based responses to Uncle Bob’s assertions, which range from “solar is taking coal jobs to “solar is unreliable”. In this part one of the series, Shugar debunks the myth that “all those solar panels are made in China”.

Uncle Bob may have said at Thanksgiving dinner, “well, all these solar panels, they’re coming from China”.

How do you respond? “That’s wrong,” Shugar says. “You say I love you, Uncle Bob. But that’s not what’s happening.”

The facts are:

• The largest manufacturer of solar panels for the United States is a U.S. company that was started over 20 years ago called First Solar and headquartered in Arizona.
• Now in addition to First Solar, over 18 solar panel factories in the United States are manufacturing to meet U.S. demand.
• After the Inflation Reduction Act legislation was passed in 2022, there have been over 50 new solar panel factory announcements, representing over $14 billion of investment.
• Solar, by the way, was invented in the U.S. by Bell Labs in the 50s. And it’s great to see a resurgence of manufacturing activity in the United States.

Episode 1

For more on domestic manufacturing, read How the IRA is changing the U.S. solar manufacturing landscape.

We’ll continue this series with fact-based responses to additional myths such as: What about when the sun doesn’t shine? What about nuclear–that’s clean and reliable? And solar sounds great, but it’s too expensive. Right? Solar takes too much land. There’s gonna be no room for farms if we have solar panels.

Stay tuned as we unpack these objections, so you’re ready for next Thanksgiving dinner (or other dinner parties) with Uncle Bob.

Dan Shugar is founder and CEO of Nextracker. For over 30 years, he has been a leading voice in business, technology and climate policy, advancing solar and climate technology solutions in the U.S. and around the globe. He has numerous patents and published 50 technical papers. He currently sits on the Board of Directors of the American Clean Power Association (ACP) and the Solar Energy Industry Association (SEIA).

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Can you tell solar actuation systems apart? Knowing what's in an actuator and how it's tested is paramount.

Solar tracker design has become more challenging than ever as some utility-scale solar projects require larger module arrays, while others contend with complex terrain, unique environmental conditions, and ongoing pressure to control costs.

The actuation system in utility-scale solar trackers, the part that drives the tracker motion, will have an outsized impact on project performance. But many solar professionals may struggle to spot the differences between one actuation system and another. How can you know if the actuation system in your next project will be optimized according to need?

An actuator or drive should not be viewed as a one-size-fits-all component. It’s not a good idea to source actuation systems by comparing some data points on a product spec sheet and assuming that all similarly sized drives are alike. First, be sure to understand the solar project’s structural requirements and the torque demands that will be placed on the actuation system throughout its operating lifetime.

Basics of torque

Torque is a measurement of the force that causes something to rotate around a point. It is most often expressed in kilonewton (kN) for solar applications since one kilonewton represents approximately 224.8 pounds of force (lbf). This measurement is used to size the torque required to rotate something, like a 15,000-lb. array of solar modules attached to a steel tube for example. Torque is also measured by the force needed to hold that same array in a stationary position ensuring the array can survive forces such as wind or imbalances of the array when tilted.

It’s essential for large-scale solar projects to optimize actuation systems according to structural loads and other design parameters. Oversizing the actuation system means taking on unnecessary added costs for the project. Under sizing the system means taking on unnecessary risk, putting plant reliability and longevity in jeopardy.

Why torque matters

During normal operations, single-axis tracker systems can be expected to make small changes in module tilt angle throughout the day to optimize energy output. In the early morning and the late afternoon, the module array may point as much as 60+ degrees from horizontal. The system might also perform backtracking, reversing the tilt angle to reduce energy losses due to shading. Or it might make other adjustments to optimize yield using bifacial modules or to account for variable terrain. All these conditions can apply forces that measure in the hundreds of kN or tens of thousands of pounds of force.

Torque plays a critical role in enabling systems to carry out routine maintenance and respond to extreme weather. Technicians might need to reposition the array to inspect equipment, perform module cleaning, carry out vegetation management, or complete other tasks that increase yield and maintain system uptime. The threat of hail may require the array to be tilted more than 70 degrees to mitigate damage, at the same time ensuring there is enough torque to withstand the increased impact of wind due to the increased tilt angle.

For a system that rotates twice a day reliably for 25+ years, the potential for failure is always present. What do you do if actuator system performance might become less reliable long before the project reaches its expected lifetime?

To safeguard projects from system failure, from having to choose between replacing drives or reverting to a fixed-tilt configuration, product engineers can design in a margin of safety. The safety margin should come from a robust set of field data and thorough, solar-specific testing.

What’s in your actuator?

One of the biggest mistakes you can make when considering what actuator to use would be to evaluate a drive based on a single number and relying on generic engineering and testing not specific to the operating conditions for solar infrastructure. Testing procedures for different applications can vary considerably, even if they generate similar numbers on the product datasheet. You ought to know inputs and outputs. How were the test results derived? How applicable are they to large-scale solar applications?

Product engineers who test actuation systems for solar tracking applications design test plans based on real-world scenarios. Following the concept of Pareto efficiency, engineers look for opportunities to increase loads for one set of scenarios without decreasing loads for other scenarios. This process continues until it reaches an optimal state where no further improvement can be made without an equivalent tradeoff.

Engineers perform static and dynamic testing to measure all the ways that actuation systems perform under various loads. They perform accelerated life testing to detect failure points in the lab faster than would be possible out in the field. They also monitor system performance throughout testing so we can analyze results and improve understanding of how systems will respond to conditions at the project site.

To make sure the system you are designing as tracker manufacturer or specifying as an EPC or developer is optimized according to need, work with suppliers who provide project-level consultation. Make sure your supplier understands solar applications and builds drives specifically for solar infrastructure. Without test results or the underlying data to support the figures you see on a product spec sheet, ask yourself: What else don’t I know about this drive?

Kyle Zech is senior vice president, advanced manufacturing technology at Kinematics, where he leads the development and implementation of manufacturing technologies, systems, and processes. Under his guidance, Kinematics has increased annual production volumes tenfold while simultaneously improving product quality by 4 levels (AGMA). Kyle is named on multiple Kinematics manufacturing technology patents.

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In its weekly update for pv magazine, Solcast, a DNV company, reports that North America saw irradiance below average, primarily due to the stormy conditions that prevailed during the second half of January.

From pv magazine global

Most of North America saw irradiance below average, primarily due to the stormy conditions that prevailed during the second half of January, according to data analyzed by Solcast via the Solcast API. Despite a cold and dry start in the north, low pressure over the Pacific drove moisture across the West Coast, delivering below-average irradiance. Humidity in the Gulf led to cloud and rain over Florida, but left a wide strip of clear dry conditions and high irradiance from Mexico to the Carolinas.

In January, northern latitudes typically receive the lowest monthly irradiance they will all year, due to short days and the sun being low in the sky, as well as winter storm fronts. This means that in locations further north even large increases relative to the average, might be low in terms of daily irradiance received or power generated by solar assets.

The early days of January were dominated by a polar vortex that brought a surge of cold air across the North Western region, pushed by a high-pressure system in the Pacific. This caused Vancouver’s record-breaking low temperature, with morning lows down to -16 C. On the other side of the continent, a similar low-pressure system led to cold and dry conditions in the North Eastern tip of the continent.

Mid-month, a sudden shift brought about by a deep low-pressure system north of Hawaii reversed the patterns earlier in the month, driving moisture and cloud from the Pacific onto the West Coast. This pattern prevailed, leading to the lower-than-average irradiance seen in the total monthly results. Just a few weeks after the record low, Vancouver saw record January high temperatures at 14.3 C.

From Baja to the Carolinas, there was a band of higher-than-normal irradiance. Other than Florida, the Gulf Coast received irradiance 10 to 20% above average for January. A stream of humidity across Central America led to rain and cloud across Florida and the Caribbean. This pattern also led to the drier conditions further north.

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 information is used by more than 300 companies managing over 150 GW of solar assets throughout the world.

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Registration through the portal is required to obtain a registration number to be included on the income tax return filings needed to claim direct cash payment or transfer credits.

On December 22, 2023, the IRS opened the pre-filing registration portal for credits to be claimed under the Inflation Reduction Act of 2022 (IRA). Registration through the portal is required to obtain a registration number to be included on the income tax return filings needed to claim the tax credits.

This registration impacts both tax exempt entities going the elective pay route to receive a direct cash payment from the IRS and those entities seeking to transfer credits to a third-party buyer in exchange for cash.

IRA background

The IRA has breathed new life into energy credits. Prior to the IRA, solar and other clean energy tax credits that had been in place for many years were starting down a path to sunset.

Two of the most significant new components embedded within the IRA legislation is the ability for non-profit entities to pursue elective pay credits, and for-profit entities to transfer tax credits earned in exchange for cash. However, like many of the other new aspects of the tax code promulgated through the IRA, it has come with new processes and requirements for those seeking to take advantage of these opportunities.

Prior experience suggests we should expect a bit of turbulence as the tools created by the IRS go live.

The registration process

The IRS released a 73-page registration guidebook outlining the details of the rules. Moving forward on energy projects requires the guidance to be broken down and a detailed review of the new guidebook will map the process for thousands of taxpayers over the next decade. All registrations will be processed through a newly created IRA pre-registration filing portal.

One taxpayer – one registration

Organizations and taxpayers are allowed only one pre-filing registration for the applicable tax period. As such, a taxpayer must apply for the registration numbers for every credit it intends to claim within one filling.

This pre-registration can be amended or updated, but only after the review of the initial submission has been reviewed by the IRS. Once a registration number has been assigned to a taxpayer, updates or amendments to that registration number must be made prior to it being used in a filing.

Pre-filing registration should occur after a project is “placed in service” and at the beginning of the tax period in which the tax credit is earned. In terms of a “deadline,” it is suggested that a pre-filing registration should be submitted at least 120 days prior to the due date for the tax return on which the credit will be reported, including any allowable extension periods.

The details

Taxpayers will need to fill out two sections to complete the pre-filing registration. The first section collects general information regarding the taxpayer. The second section, based on the inputs from the general section, will allow the taxpayer to input all relevant information for specific credits to be claimed.

The first section asks for basic information, such as: the tax period of the election; the filer’s EIN; any information about subsidiaries included in a consolidated group of corporations; the entities name as it will appear on the ultimate tax return; the entities (not project) address (this must be the address used on the last income tax return filed by the entity, if this isn’t a newly formed organization or first time filer);bank account information.

In a situation where there is a parent of a consolidated group of corporations as the registrant, the EIN and name must be that of the parent. Information regarding the subsidiaries can be captured during the subsequent credit-specific information input. The parent of a consolidated group of corporations will register on behalf of itself and will act as an “agent” for subsidiaries included in the group. When entering subsequent credit-specific information, the parent corporation will provide the subsidiary name and EIN for each facility or property being registered that is owned by the subsidiary.

I’m through the General Registration Section, now what?

This is where the fun really starts. The IRS portal offers two options at this juncture, manual entry or bulk upload. Think of this as the difference of entering a set of an individual set of data for a single project (on a project-by-project basis) versus uploading a spreadsheet file with all of this information for each project embedded into it.

Project information required for this section includes; choice of election (e.g., elective pay or transfer); if applicable, confirmation of the entity as a subsidiary in a consolidated group of corporations; the date construction began; the date the project was placed in service; the property location; details on any joint ownership in the project; and finally (and an interesting requirement) the sources of funds.

You aren’t done yet!

Aside from the information discussed in the “general” and “detailed” sections, each credit type will request supporting documentation. With the IRA, a number of new and enhanced credits are going to be registered, including: Section 30C (alternative fuel refueling property), Section 45 (production tax credit), 45Q (carbon oxide sequestration credit), Section 45U (nuclear power production), Section 45V (clean hydrogen), Section 45W (commercial clean vehicles), Section 45X (advanced manufacturing production), Section 48C (qualifying advanced energy projects), and the Section 48 energy investment tax credit we have all come to know and love.

The additional supporting documentation required to register includes:

• Proof of ownership of the facility/property with respect to which the credit is computed
• Construction permit showing commencement of construction
• Permits to operate from utility (only if connected to the grid, or if not connected to the grid electrical permits to operate from an authority having jurisdiction)

A learning process

As more and more guidance comes out, the associated requirements that come along with the opportunity to harvest substantial tax credits will be a learning process.

While elective pay or transferable credit registration requirements don’t appear to be significant, they are another step that needs careful consideration. Complete registrations are more likely to be approved and not questioned for resubmittal.

Prior experience indicates that there may be delays in turnaround of registration requests regardless, those that don’t register with correct and complete information can only anticipate even longer delays prior to ultimately accessing the credits. And in this case, time is literally money.

Joel Laubenstein is a principal and a leader in Baker Tilly’s Development and Community Advisory – Energy practice. He and his team specialize in compliance, energy, and infrastructure project execution advisory, outsourced grant writing, outsourced project development, and additional capital procurement.

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In its weekly update for pv magazine, Solcast, a DNV company, reports that, last year, large regions were 10% or more above long term trends for solar radiation, including Western and Northern Europe, Eurasia, much of China, Southern Australia, the Midwestern and Southern U.S., Central and most of South America.

From pv magazine global

2023 was not only the hottest year in modern records, but was also the sunniest year so far this century, according to analysis by Solcast.

2023’s margin as the sunniest year of the century was particularly large for non-polar landmasses – the places we live, and the places
where our solar PV systems are located, as El Nino kept moisture and cloud over the Pacific Ocean, and deviations in the Arctic circulation pulled low pressure systems further north into the Arctic Ocean. Large regions were 10% or more above long term trends, including Western and Northern Europe, Eurasia, much of China, Southern Australia, the Midwestern and Southern US, Central and most of South America.

2023: Sunniest year so far this century

Analysis by Solcast reveals that for the entire planet, 2023 saw the highest total solar irradiance of any year this century, using data from Solcast and ECMWF ERA5. 2023 saw total solar irradiance near 0.5% above the long-term average – a small percentage, but equating to an increase of solar energy received of approximately 16,000 TJ.

The anomaly was 1% for combined non-polar land areas, a much larger deviation than any seen in the last 15 years. This deviation was larger than the global total, due to increased cloud formation over the oceans offsetting some of the reduced cloud formation over non-polar land areas.

Americas

The Americas saw above average irradiance, as an early El Nino created a lot of moisture and cloud over the tropical Pacific Ocean, pulling cloud away from the surrounding land areas.

In Central and South America, Brazil and neighboring countries to the north saw the highest irradiance in over 15 years, in a year marked by significant drought in the Amazon. Argentina and Chile further south saw near or slightly above average irradiance. In total, 13 countries in the Americas saw the highest irradiance year in over a decade, including Brazil, Colombia, Venezuela, Guatemala, Dominican Republic, Haiti, Nicaragua and Costa Rica.

North America saw slightly above average irradiance in total, although the North-West and North-East United States both saw cloudier than average conditions. In the North-East conditions will also have been impacted by aerosols, from the Canadian wildfires that burned
for much of the year.

In the U.S. this was offset by large areas of above average irradiance in the Mid-West and South. This was good news for solar production in Texas, which had another record year of solar capacity installations and generation according to the SEIA.

Africa, Europe and the Middle East

Western Europe and Northern Europe saw well above average irradiance, due to Arctic circulations contracting north, reducing the intensity of associated cloud from low pressure systems. Estonia saw the sunniest year they have seen in over 10 years. Whilst these patterns delivered several large and intense storms, cloud cover was lower than average.

Eastern Europe and the Middle East saw below average irradiance as moisture from both the Eastern Mediterranean and Indian Ocean was pushed onshore. Much of Africa saw a relatively normal year for irradiance, with only small deviations relative to average. Despite small deviations, Tunisia, Liberia, Eritrea, Kenya, Gabon, Equatorial Guinea, and Rwanda saw more irradiance in 2023 than they have for any other year in the last decade.

Asia

China saw above average irradiance, with some areas seeing 110% of long term averages, although this was less intense towards the coast. Japan saw the highest national average irradiance in over a decade, especially along the eastern coast near Tokyo, as anomalous westerly winds kept Pacific moisture offshore.

A positive Indian Ocean Dipole contributed to overall below average irradiance across most of India, although the south-western Indian states saw above average irradiance. Across Asia, Kyrgyzstan, Tajikistan, Bhutan, and Japan saw higher irradiance than the last 10 years.

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 information is used by more than 300 companies managing over 150 GW of solar assets throughout the world.

ERA5 is the fifth generation ECMWF atmospheric reanalysis of the global climate covering the period from January 1940 to present. ERA5 is produced by the Copernicus Climate Change Service (C3S) at ECMWF.

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How amplified quality incidents can send ripples through the industry, affecting solar perception and adoption.

Despite the infrequent failures and ‘thermal events’ that are verifiably caused by solar, the hundreds of thousands of solar ecosystem members globally suffer when an issue with a solar site gains media attention. In most cases, a sober root-cause analysis will uncover a relatively minor issue that started a cascade of other, more serious problems. However, most resulting mainstream media coverage and industry scuttlebutt oversimplifies or ignores the root cause entirely; that’s easier to write about, makes for better headlines, gets more clicks, and helps disperse blame.

A similar thing happens with self-driving cars. Of the 6.7 million reported car accidents on U.S. roadways in 2019, only 327 accidents involved self-driving vehicles. Even in the face of this miniscule percentage, the latter received outsized attention in the media and rarely is the coverage truly nuanced.

For the reported thermal events in the United States, fire departments around the nation responded to an average of 346,800 home structure fires from 2015 to 2019. According to the National Fire Protection Association, the top five leading causes of home fires, in order, are cooking, heating, electrical distribution and lighting equipment, intentional fire setting, and smoking materials. Note that electrical distribution includes electrical outlets, outdated/worn electrical wiring, cords and electrical circuits, old appliances, light fixtures, and portable heaters and does not account for rooftop solar systems.

Fires caused by rooftop PV systems are historically underreported, but the Solar Energy Industries Association maintains that spontaneous combustion from a PV system is extremely rare. The quantitative analysis determined an annual fire incident rate of 0.0289 per MW. A 2022 fault tree analysis published in the Journal of Building Engineering revealed that modules, isolators, inverters, and connectors play a significant role in igniting PV fires, with connectors contributing to 17% of incidents.

The reality is that fires found to have been caused by solar equipment are vanishingly rare. Just like how a self-driving car that crashes on the highway makes the evening news, there is no shortage of media attention when there is a presumption that a structure fire was caused by solar. In the face of the challenge of misconceptions about solar equipment, the industry must come to terms with the reality of collective responsibility and modify its behaviors and practices accordingly. The outcome will be fewer bad headlines for solar and a more unified solar sector overall.

Embracing responsibility, together

One of the challenges with attributing responsibility for a problem on a solar installation is the number of companies involved in the value chain. A fertile ecosystem of blamestorming develops when equipment from half a dozen vendors is deployed at an installation, a seventh designs the system, an eighth installs it, a ninth maintains it, and a tenth owns it. In some cases, this number is even larger. For any individual entity, the path of least resistance is to point to one of the others for culpability. In reality, the companies technically all share responsibility. Reputationally, however, the entire solar industry suffers; all are punished.

To protect the next round of growth, the industry must come to terms with the fact that solar is a team sport. Reliable and efficient solar energy systems depend on the expertise of installers and engineering, procurement, and construction (EPC) companies. These installers, in turn, lean on quality system design and skilled labor for their success. Hardware and software providers occupy a pivotal role in delivering solutions that are not only reliable but also user-friendly and feature rich. The points at which the work of these entities intersect, however, have been too transactional for too long.

‘Crosstalk’ and the solar value chain

Since stating a problem without suggesting a (possible) solution is not productive, here is a recommendation for every company involved in the solar industry: According to the Department of Energy (DOE), solar system quality issues fall into three categories: design flaws, faulty installation, and equipment defects. Any possible solution, therefore, should address one, several, or a combination of these three possible causes. A worthy and real example through which to investigate the blame-reputation dialectic is ‘crosstalk.’

Any large electrical system with long wire runs and multiple transmitters is susceptible to crosstalk. The term is solar industry shorthand for electromagnetic interference (EMI), created by the interaction of two or more electromagnetic fields of adjacent energized cables. The phenomenon is present in wired communications in home automation, automobiles, or entertainment systems in commercial buildings and residences.

Crosstalk can be minimized, even eliminated, when several preconditions are met, starting with well-trained engineers who design systems such that crosstalk does not occur. In large-scale C&I solar installations, the most efficient wire layouts often require that home runs to inverters share cable races. When array voltage increases towards the inverter-side of the cable run, as multiple strings come together, the close proximity of these cables can result in mutual EMI radiation. That is not a big issue for shielded cables that only carry current, but this type of interference can cause problems for data communications signals.

The installation process is another node in crosstalk mitigation. Installation teams must be well-trained, follow equipment vendor installation guidelines, use high-quality components, and install those components correctly. For systems that were designed according to crosstalk avoidance strategies but were not installed properly, diagnosis and rework are usually costly, margin-eroding exercises that can foul reputations and sour customer relationships.

The final piece of the quality puzzle is the quality of the products being deployed. Suppliers should have a continuous improvement approach to quality with a systematic root cause corrective action analysis, thorough documentation, and a great support team.

Hanging together

Although a single self-driving car accident damages the reputation of all purveyors of self-driving cars, we do not impugn the automobile industry at large. In reality, self-driving car accidents are rare, just like fires caused by solar equipment. Perception, however, often becomes reality. Every company in the value chain has a role in upholding the reputation of solar energy. And that goes for every step in the solar value chain, too; from engineering, procurement and construction to installation teams and distributors.

By prioritizing quality in design, installation, equipment, and service, we collectively propel the growth and success of solar energy solutions. This shared commitment contributes significantly to paving the way for a more sustainable future powered by the brilliance of solar innovation.

Beyond our close-knit solar community, any hiccups in commercial installations tend to cast a spotlight on ‘solar’ as the culprit. This holds true for the customers we collectively serve. Whether for better or worse, we find ourselves sharing the same ‘solar’ identity, which implies that our fortunes and misfortunes are connected. The solar industry is maturing rapidly, and the quality across every aspect of the value chain is good, but focusing on continuous improvement is critical.

JD Dillon is chief marketing officer at Tigo Energy. His experience spans the U.S. Armed Forces, semiconductors, solid-state drive, and the solar industry. His functional leadership has had an impact on pricing, new product introduction, customer experience, and communications at all levels.

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A benefit to designing the roof for optimal solar production is the ability to plan for all the ventilation and plumbing to be on the north-facing side to both maximize system size and prevent any energy losses from shading.

Most of the time when residential PV systems are designed, they are optimized within the limitations of the already-built roof. It is not often that roofs are designed to optimize PV production. But that is the exact opportunity that I get while building not your average dream home.

With years of experience in solar, I assumed that this would be one of the easiest parts of the process – especially for a one-story home with such a high roof surface area to square footage ratio. I thought that all I would need is the right azimuth and tilt. Well, I quickly learned that it’s a bit more complicated.

Luckily, the azimuth was straightforward since the lot is completely open without any obstructions. However, since most houses are designed to align with the road, completely ignoring this rule of thumb feels contrarian. At the same time, using solar orientation and the sun’s ecliptic feels both organic and instinctive to this process. It made me take a step back and wonder how society has distanced itself so much from the natural world that we use something as arbitrary and temporary as a road to orient something as important as our homes. But there was no time for philosophizing when there were important calculations and opportunity costs regarding the roof angle and energy production to consider.

When I was originally dreaming up the house design, I had envisioned a single-pitch roof, with an angle optimized for solar. Since Minnesota has a latitude of about 45°, that is typically the recommended angle for solar panels since that puts them horizontal to the sun during the equinox. But a roof with such a high angle introduces several setbacks. Such a steep roof adds extra volume, increasing build and system installation costs, and therefore the system payback period. Plus, it would create a very inaesthetic and unbalanced building design, with the north exterior wall being double the height of the south wall. In terms of power density, the higher angle creates more surface area, supporting a small C&I system at a 30 kW – much larger than I need.

That’s when we evaluated the clerestory roof, with two differently-angled sloping sides and a vertical, dividing wall. This roof type adds in some additional lighting and ventilation options, while also overcoming many of the challenges of the shed design. Unfortunately, it also creates some weight-bearing structural complications at such a high angle that make the build cost inefficient.

After that, we tried a saltbox roof, which is a pitched roof with unequal sides, one short and high and the other long and low. The thought around this design is that it creates a large surface for a power dense roof.

According to SolarEdge’s Designer tool, if the long, south-facing side were at 34°, I could fit a whopping 55 solar panels for a 22 kWp system to achieve 33 MWh of annual energy production. But this angle is significantly lower than the standard recommendation of 45°, meaning that the energy density would be compromised.

According to Chris Bunch, VP of design and engineering at Powur, the 45° recommendations is “only part of the equation. I think the more important thing is when is electricity going to be used. Is it mostly in the summer? Is mostly in the winter? What sort of energy is driving the heating in the winter and the cooling in the summer? And the anticipated electrical demand throughout the year is important.”

Unfortunately, without an electric bill to show energy usage patterns, this type of information is hard to know in a new build. And it can be even more difficult to estimate for a passive house that is specifically being designed to reduce energy demand. However, in general, houses in Minnesota have a higher energy load in the winter due to the extremely cold weather. And as I’m planning for the house to be all electric, with no gas connection, this will likely hold true. As we were contemplating options, other suggestions arose such as a flat roof or even a ground mount PV system.

But then lightning struck when I suggested turning the saltbox roof 180°, so that the short and high side of the roof would face the south. While that leads to less surface area at a higher angle of 40°, making it less power dense, it becomes more energy dense and better optimized for the higher energy demand in the winter.

With this new roof design, I can fit on a 12 kWp PV system with an annual yield of 18.6 MWh. While this would be 55% the size of the 22 kWp systems mentioned above, its yield would be 56% of the 34° roof and 59% of the 18° roof. And an added benefit of a steeper roof angle according to Bunch is that it can help with snow shedding.

With Minnesota being a standard net-metering incentive structure, this process was more straightforward than it would have been if I were building in a state with a more complex rate structure, such as time of use. As Carina Brockl, CRO of Aurora Solar noted, “Generally south-facing PV systems with less shade are going to do well, but certain net metering programs like the Net Billing Tariff in California actually favor a southwest orientation.”

The other benefit to designing the roof for optimal solar production per Bunch is the ability to plan for all the ventilation and plumbing to be on the north-facing side to both maximize system size and prevent any energy losses from shading.

Now that I have a roof to put over my head, I still need to decide on the components and appliances for energy production, consumption and potentially storage. I’ll be diving into the product choices and the different types of appliances, plus energy efficiency considerations further into the process.

Jessica Fishman is a strategic marketing leader with nearly 20 years’ experience, including seven years as head of global public and media relations at inverter maker SolarEdge. Passionate about addressing climate change by accelerating the clean energy transition, she has worked at leading renewables companies, building marketing and communications departments.

Read the first in the series Building not your average dream home. The second in the series on finding an architect can be viewed here. The third in the series on finding a builder can be viewed here.

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In a new weekly update for pv magazine, Solcast, a DNV company, reports that areas in the totality, where the moon completely blocks the sun, will see a 100% loss in solar generation for the duration of the totality.

As solar capacity increases, the grid impact of subsequent major solar events also increases. On April 8, a total eclipse will pass from Mexico, across Texas and up the East Coast, with most of the continental U.S. experiencing a significant drop in solar generation. The eclipse will occur from Noon to the early afternoon, when solar generation is at its highest. It is too early to predict weather conditions for the day, in particular high-resolution cloud modeling, so this analysis is based on clearsky data via the Solcast API.

Areas in the totality, where the moon completely blocks the sun, will see a 100% loss in solar generation for the duration of the totality. However, the overall effects of the eclipse will cost up to 16% of daily total clear sky irradiance in areas most affected.

While it is too early to predict the precise cloud impacts on the day, Grid Operators will already be preparing for the maximum potential impact, a temporary total loss of solar generation and a fast ramp of solar decreasing then increasing. For areas directly in the path of the eclipse, the maximum duration will be over 90 minutes of impacted generation, and a total loss of up to 6 minutes. In every grid analyzed, the rate at which solar generation drops off and then picks back up again, is faster than grids normally see in the morning and evening.

Due to the large proportion of utility scale assets in ERCOT, Texas will be heavily impacted by the effects of the eclipse. Individual assets will lose up to 16% of their daily irradiance, but the wide area covered by ERCOT means that the overall loss to the grid will be up to 11.7% of daily utility scale solar generation. At current capacity, that would be 16.9 GWh, though the rapid increase in capacity in ERCOT, and known projects coming online before April makes it likely this number could be higher. Solcast’s grid aggregation model shows that the ramp will be slightly steeper than normally seen in the morning or evening, peaking at a rate of 250 MW/minute. The fast change in generation is what can cause instability in the grid, so asset managers, energy traders and grid operators will be working to maintain stability whilst making the most of volatile energy prices.

As the eclipse moves up the East Coast, it will impact both NYISO and ISO-NE. These regions have less utility scale solar than Texas, so the impact will mostly be seen in ‘behind-the-meter’ residential rooftop solar generation. For each grid, the impacts are fairly similar. NYISO will lose up to 10.91% of their daily rooftop generation, and up to 3.1 GWh of power. Being further south, and hit by the eclipse slightly earlier explains the difference with ISO-NE. New England will lose up to 9.85% of its daily behind-the-meter generation, though differences in installed capacity make this a higher 3.7 GWh. Notably the ramp rate is much higher than the morning or afternoon ramps, as irradiance will drop from almost the daily maximum to zero in approximately 40 minutes. This will require active management from the grid operators to maintain stability.

CAISO in California will also see impacts from this eclipse, though being so far from the path of totality, the effects will be less than seen in the partial annular eclipse in September 2023. Despite seeing a lower proportional effect from grids in the North-East, only 5.72% of daily generation, increased levels of rooftop solar in California mean that the energy losses will be greater than either NYISO or ISO-NE, up to 4.0 GWh.

While the impact of this eclipse is significant, it is predictable, and grid operators are already preparing and planning for the impacts. Large storm events, snow dump events and large heavy cloud fronts are less spectacular but can have even bigger impacts on whole-day solar generation. These events are also harder to plan for and predict, which makes it more important for asset owners and grid operators to plan and manage the impact of weather on solar generation as solar increases in the generation mix.

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 information is used by more than 300 companies managing over 150 GW of solar assets throughout the world.

This article was amended to correct the figure in this statement: “the wide area covered by ERCOT means that the overall loss to the grid will be up to 11.7% of daily utility scale solar generation”.

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At the close of 2023, the city passed a series of zoning amendments, as part of Mayor Adams’ 'City of Yes for Carbon Neutrality' initiative, which will relax burdensome zoning restrictions on solar development.

As progressive as the Empire City is, up until recently NYC’s transition toward renewable energy had suffered paralysis by its own laws and regulations. For example, despite much of the city’s suburbs’ flat-topped roofs being ideal to house rooftop systems, the city’s stringent zoning restrictions allowed for the majority of rooftops to only be outfitted with small, unsubstantial systems.

But at the close of 2023, the city passed a series of zoning amendments, as part of Mayor Adams’ ‘City of Yes for Carbon Neutrality’ initiative, which will relax burdensome zoning restrictions on solar development. These changes unlock 5 gigawatts of previously undeveloped capacity for rooftop solar development across more than 50,000 buildings and more than 1 million homes in NYC. In addition, 8,500 acres of parking lots will be re-zoned to allow for solar installations – equivalent to 10x the acreage of Central Park.

The relaxed zoning restrictions will usher in a new wave of solar development in time for homeowners to take advantage of a wide variety of federal and state incentives aimed at making solar installations affordable for all. For residents of New York City, there is an additional incentive of note. Beginning in 2024, the city’s property tax abatement (PTA), which was set at 20%, will be increased to cover 30% of the cost of a solar installation, over the course of four years. And the 30% rate has been extended through 2035.

The laxed zoning restrictions and financial incentives will make solar installation both logistically and economically feasible for property owners throughout the five boroughs, a necessary feat given New York State’s aggressive climate goals and the city’s implementation of Local Law 97. Local Law 97 (LL 97), which took effect at the start of the year, requires buildings greater than 25,000 square feet to reduce carbon emissions by 40% by 2030. Buildings that exceed emissions limits or fail to meet adequate reductions in emissions will face monetary penalties. Solar energy will play a significant role in ensuring buildings meet LL 97 regulations, and the zoning changes adopted by the City of Yes Carbon Neutrality amendments and the city’s increased property tax abatement are crucial to LL 97’s practicality and success.

These regulations and incentives have come together to create a “solar mecca” in the Big Apple that will propel the city toward its emissions reduction goals, while driving significant economic impact. The city’s comptroller predicts that the influx of solar-development will create 13,000 clean-energy jobs over the course of the next 8 years with experts predicting a potential market opportunity of more than $23 billion.

T.R. Ludwig is a clean energy leader with over a decade of experience in various management and executive roles within the solar industry. He is the CEO and co-founder of both Brooklyn SolarWorks and Brooklyn Solar Canopy Co. and serves as treasurer for NYSEIA. He has led solar companies both large and small, with a focus on sales, marketing, and finance, and helped pioneer solar lending in the Northeast market. T.R. received his MBA from the Maastricht School of Management in the Netherlands and was among the first solar professionals in the United States to become NABCEP Technical Sales certified.

This article was amended to say that the opportunity is worth $23 billion rather than million.

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In its last 2023 update for pv magazine, Solcast, a DNV company, presents a long-term analysis on historical average irradiance on Christmas day.

From pv magazine global

There are no holidays for solar production. As many cultures around the world prepare for a holiday season, the Solcast team has run a long-term analysis on historical average irradiance on Christmas day, and a look ahead at the forecasts for Europe and the US, using data from the Solcast API.

Christmas Day is just a few days after the Solstice, when the day is at its longest in the southern hemisphere and shortest in the northern hemisphere. This is the driving factor in the long-term average irradiance trends, where you can see much lower levels of total irradiance in the northern hemisphere.

Whilst the amount of irradiance available is based on the length of the day, long-term cloud patterns are also present in the data, which you can see on the western coasts of South America, Africa and Australia. Sub-tropical latitudes in the Southern Hemisphere see more easterly winds as the sub-tropical ridge pushes further south, keeping moisture offshore on the west coast and bringing more moisture and cloud to the east coasts.This year, much of the eastern US will receive below-average irradiance over Christmas, as an eastward-tracking low-pressure system brings rain and snow across the continent. However, the system likely won’t make it to the northeastern USA during the daytime,
leaving New England to see above-average irradiance. A high-pressure system following the rain and snow will bring sun to the Midwest and West Coast of the US, delivering average to above-average irradiance for the day.

Europe will see more variation than the US compared to long-term averages. Low-pressure systems in the North Sea will push westerly winds and Atlantic moisture across the British Isles, northern France and Germany. Further south, light winds and a high-pressure system
will keep skies clearer and sunnier than usual. This will feel like a typical December day, as the Mediterranean coast has relatively less cloudy winters than further north.

Particularly noticeable in the long-term average is the difference between Spain and Southern France, as the Pyrenees mountain range shields the Iberian peninsula from moist and cold northerly winds.

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.

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In contrast with traditional panels, thin-film solar modules are much more adaptable to these agricultural situations, thanks to their flexible, lightweight design.

As solar power has been developed and popularized across the globe over the last several decades, the industry has given way to more recent innovation that allows for higher efficiency in irregular places: thin-film solar cells. These lightweight, flexible cells are capable of attachment to surfaces of nearly any shape or design, thanks to their flexibility, while requiring minimal structural supports, due to their light weight. With this technology, solar power is able to be harnessed in a variety of applications and places where previously thought impossible, due to the rigid structure and heavy nature of traditional solar panels.

And now, thin-film solar modules are ready to take on their next challenge: agrivoltaics.

As the impacts of climate change worsen each year, domestic farmers have begun to struggle to keep their crops healthy, as the sun beats down on them with punishingly-high temperatures. Thankfully, a new use of solar technology, known as agrivoltaics (APV), have come to help.

Farmers need elevated coverage to provide partial shade for their struggling crops and solar modules need ample space to soak in the sunlight to generate power. APV combines these two needs, by placing arrays of solar modules above areas of crop growth, to provide partial shade, which reduces sunburn on the land, reduces water evaporation, and insulates the crops from extreme cold and extreme heat, all while giving farmers the primary benefit of solar power utilization: a second revenue stream through power generation.

And now, thin-film solar PV is ready to supercharge this powerful relationship.

Current challenges facing agrivoltaics

If you were to set up your agrivoltaic system with traditional, rigid solar panels, it’s possible you will run into some logistical issues. Traditional panels are quite heavy, requiring substantial support structures, and are so large that they provide more shade than necessary for most crops, and can stifle their health and growth. The goal of a balanced APV system is to provide just the right amount of shade that keeps the land from dehydration while also allowing the proper amount of sunlight to shine through and help the crops grow. Unfortunately, the rigid nature of traditional solar panels limits the ability to strike this delicate balance.

Most current APV installations that utilize rigid panels will typically consist of a row of solar panels next to a row of crops, taking about half of the land out of production, and make crop care and harvesting quite difficult. Heavy machinery employed in standard maintenance and harvesting processes often must be replaced by expensive manual labor to avoid damage to the solar system.

Lastly, the electrical conduit for traditional solar modules is installed underground; this disables flood irrigation and therefore can limit the variety of crops that are able to be grown in symbiosis with a traditional solar array. If only certain crops can work within the module, then it may end up not being a good fit for an otherwise interested farmer.

Key benefits of thin-film for agrivoltaics

In contrast with traditional panels, thin-film solar cells are much more adaptable to these agricultural situations, thanks to their flexible, lightweight design. Thin-film agrivoltaics overcome the challenges of their rigid, heavy counterparts by consisting of a series of solar crossbars covered in solar that are elevated high above the protected crops, which allows for:

1. The full area to be used for growing crops
2. The full area to receive partial sun and shade during daylight hours, rather than the full sun or full shade situation offered by traditional solar panels, which stifles crop growth
3. The crops to be serviced and harvested using whatever machinery that is typically used, thanks to thin-film solar’s lightweight design allowing for the technology to be implemented at such a high elevation

Agrivoltaics, using thin-film solar technology, allow for the proper distribution of shade and sunlight onto the ground beneath it.

The use of thin-film solar cells also allows for greater energy savings, a healthier crop yield, and increased water savings.

Perhaps best of all, is the ability for thin-film modules to continue functioning after being struck, impaled or damaged. Climate change continues to bring about dangerous, unpredictable weather phenomena, where high winds carrying various items and debris is common. When a traditional solar cell suffers an impact, its glass coating is often shattered, creating a costly mess, the need for swift, expensive repair, and the total lack of energy production until it is properly fixed. But thin-film solar cells don’t have these same drawbacks; if a cell is punctured or damaged by outside forces, the rest of the cell will continue to function just fine, leaving only the small, damaged area in need of repair, rather than taking the whole array out of commission.

The future of thin-film for agrivoltaics

As more and more domestic farmers turn to agrivoltaics as a viable solution to increase revenues per acre, reduce on site energy costs and to bolster crop yields, we will start to see a greater embrace of thin-film solar to get the job done.

While there are plenty of applications and situations where large, traditional, rectangular solar panels are the optimal choice for solar power generation, agrivoltaics is an area that requires the flexible nature of thin-film solar technology to deftly handle the delicate relationship between crops and their need for shade and sunlight. Soon, farmers across the nation will begin to see not only the lucrative energy-saving benefits of thin-film agrivoltaics, but also the crop health benefits of it as well.

Paul Warley is CEO of Ascent Solar Technologies, Inc., maker of flexible thin-film solar panels. Prior to Ascent, Warley was president of Warley & Company LLC, a strategic advisory firm that provided executive management services, capital advisory, and M&A to middle-market companies in the service, construction, technology, oil & gas, clean energy, food, retail and green-building sectors.

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The Inflation Reduction Act and Bipartisan Infrastructure Law mark an epochal shift in the landscape of clean energy policy, heralding a new era for the solar and energy storage sectors in the U.S.

In recent years, the United States has made substantial progress in embracing a renewable energy revolution, positioning itself on a path toward a more sustainable future. This transition is being propelled by a convergence of factors, including environmental concerns, economic opportunities and advancements in technology.

With the introduction of the Inflation Reduction Act (IRA) and the Bipartisan Infrastructure Law (BIL), the U.S. is accelerating its move toward clean energy solutions.

To illustrate the extent of this progress, consider the following key statistics: In 2022, the share of renewable energy sources (RES), including hydroelectric power, in the nation’s electricity generation had reached approximately 22%; furthermore, the share of RES in the total electricity generation capacity had increased to approximately 30%.

Notably, in the transportation sector, there is also a growing awareness among consumers, who are increasingly opting for zero-emission fuels, such as electric vehicles. In 2022, the battery electric vehicles (BEVs) share in new vehicle registrations stood at 5.6%, and by the first half of 2023, the share had surged to 7.1%, according to EUPD Research estimates.

The U.S. has set ambitious targets, including achieving 100% carbon pollution-free electricity by 2035 and aiming for economy-wide net-zero greenhouse gas emissions by no later than 2050. These targets are expected to provide a significant boost to the clean energy sector in the country, further reinforcing its commitment to a sustainable and environmentally responsible future.

IRA and BIL fueling the boom

The IRA and BIL mark an epochal shift in the landscape of clean energy policy, heralding a new era for the solar and energy storage sectors in the U.S. The IRA allocates substantial resources toward addressing the climate crisis, bolstering domestic clean energy production, and solidifying the U.S. role as a global leader in clean energy manufacturing.

According to U.S. Department of Energy (DOE), a substantial investment exceeding $120 billion in the U.S. battery manufacturing and supply chain sector has been announced since the introduction of IRA and BIL. Furthermore, plans have been announced for the establishment of more than 200 new or expanded facilities dedicated to minerals, materials processing and manufacturing. This is anticipated to create over 75,000 potential job opportunities, strengthening the country’s workforce.

After the introduction of IRA and BIL, solar PV manufacturing in the U.S. has also seen a substantial surge in planned investments, amounting to nearly $13 billion, according to the DOE. Furthermore, a total of 94 new and expanded PV manufacturing plants have been announced, which could potentially create over 25,000 jobs in the country.

Surging solar sector

In recent years, the solar sector in the U.S. has outpaced other energy sources, including wind and natural gas, in terms of capacity growth. EUPD Research estimates reveal a noteworthy upward trajectory in the contribution of solar capacity to annual power capacity additions. This trend has seen a rise from 37% in 2019 to 38% in 2020, further increasing to 44% in 2021, and reaching an impressive 45% in 2022.

Annual PV capacity in the U.S. has been steadily rising in the past years, albeit with a temporary setback in 2022 caused by pandemic-related delays, enforcement of trade laws, disruptions in the supply chain, and increasing costs. (The country installed 21.1 GWdc of PV capacity in 2022, as compared to 23.1 GWdc in 2021.)

The U.S. now is on track to make an historic addition to its PV capacity in 2023. According to EUPD Research’s 2023 forecast, the U.S. is poised to achieve its largest-ever expansion in PV capacity, with an estimated 32 to 35 GWdc, if all the planned utility-scale capacity gets installed. Moreover, in the period from 2023 to 2028, the U.S. is estimated to add approximately 233 GWdc of PV capacity.

To learn more about how EUPD collects historical installed PV and storage data and make projections for future installed capacity, see EUPD Research’s Global Energy Transition (GET) Matrix.

In terms of cumulative installed PV capacity (utility-scale + C&I + residential) on a state-by-state basis, California holds the top position followed by Texas, Florida, North Carolina and Arizona. Notably, Texas is rapidly expanding its utility-scale PV capacity, and it is poised to potentially surpass California within the next two years.

Rapid expansion of battery storage

Battery energy storage has emerged as the dominant and rapidly expanding source of energy storage in the U.S. in recent years. The proportion of battery storage in the country’s energy storage capacity has surged dramatically, climbing from a mere 3% in 2017 to a substantial 36% in the first half of 2023.

In the U.S., battery storage capacity additions have been dominated by utility-scale installations. The rise of intermittent energy sources like solar and wind has made utility-scale batteries increasingly important. According to the DOE, the majority of planned utility-scale battery storage capacity is being installed alongside solar and wind facilities in the U.S.

At the end of 2022, around 9 GW/23.24 GWh of utility-scale battery storage capacity was installed in the U.S., as per EUPD Research estimates. Our projections show that in the year 2023, the U.S. is estimated to install a substantial 9.6 GW/26.4 GWh of utility-scale battery storage capacity, surpassing the cumulative installed capacity up to 2022.

In terms of total installed battery storage capacity (utility-scale + small-scale), California at present holds the top position followed by Texas, Florida, Hawaii and Arizona.

Unveiling the top installers

Crucial to the flourishing solar and storage industry in the U.S. are the downstream players, specifically installers. These entities play a pivotal role in driving sector expansion and shaping its trajectory. To ensure continued growth and success, understanding the landscape of the top installers in the country is imperative.

Against this context, EUPD Research in its recently published report “Market Leadership Study: The United States 2023” came out with a ranking of the top installers in the U.S. distributed generation market. We also conducted a comprehensive evaluation of top installers, creating a data-driven snapshot of their competitive positioning. The installers were ranked using a rigorous methodology that considers various critical factors, such as installed capacity, sector coupling, vertical integration, financing options, and more. Each of these factors was assigned a specific weighting to determine the final rankings.

EUPD Research is pleased to reveal the names of the top 10 distributed installers in the U.S., according to our report. Topping the list are industry giants Sunrun, Sunpower, and Tesla Energy, in positions 1, 2, and 3, respectively. The remaining companies in the top 10 are: Sunnova, ADT Solar, Palmetto Solar, Freedom Forever, Trinity Solar, Titan Solar Power, and Momentum Solar.

In conclusion, the U.S. stands at the cusp of an energy revolution, propelled by ambitious targets and landmark legislation. The solar PV and energy storage sectors are witnessing unprecedented growth, guided by substantial investments and a surge in installations. With industry leaders driving innovation and sustainability, the nation is poised to achieve its clean energy goals, reaffirming its commitment to a greener future.

Markus A.W. Hoehner is the founder and CEO of EUPD Research. Markus has over three decades of extensive expertise in top-level research and consulting, with a particular focus on renewable energies, the clean tech sector, and sustainable management. He is a dedicated advocate of the global energy transition and has actively championed this cause by spearheading various initiatives, projects, and enterprises aimed at fostering the expansion of sustainable industries on a global scale.

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Ensuring equitable access means guaranteeing that the benefits of the energy transition are not exclusive to privileged countries but are extended to every individual and community, allowing them to benefit from cleaner energy sources.

According to the latest World Energy Outlook 2023 from the International Energy Agency (IEA), clean energy technologies such as solar, wind, electric cars, and heat pumps are reshaping how we power our world. By 2030, the IEA foresees almost ten times more electric cars on the roads, solar generating more electricity than the entire current US power system, and renewables nearing a 50% share of the global electricity mix.

While developed countries like the EU, the U.S., and Canada are leading the way in decarbonization and electrification efforts, the challenge lies in extending these benefits to developing nations around the globe. The IEA’s projections highlight the urgency of addressing worldwide energy challenges, exploring progressive battery chemistries, and emphasizing the need for international cooperation to accelerate a clean energy future.

The unequal distribution of clean air and water worldwide highlights the need for equitable access to carbon-neutral energy. Although we have seen commendable progress, such as the share of the global population without reliable electricity access dropping by more than half between 2000 and 2023, challenges persist as 746 million individuals still lacked access to electricity in 2023. Across the globe, communities grapple with an uneven distribution of environmental resources, exacerbating health risks and perpetuating a cycle of inequality. Regions such as Sub-Saharan Africa and Southeast Asia heavily depend on diesel and coal, contributing to disproportionate environmental and wellness impacts on vulnerable populations.

Pollution-related challenges continue to affect those with fewer resources, amplifying existing social disparities. Delving into the root causes of pollution unveils deeper systemic issues, including unequal supply distribution and inadequate infrastructure. Ensuring equitable access means guaranteeing that the benefits of the energy transition are not exclusive to privileged countries but are extended to every individual and community, allowing them to benefit from cleaner energy sources.

Beyond lithium-ion

Lithium-ion batteries, currently the dominant player in energy storage, have multiple limitations. The production of lithium-ion batteries greatly impacts the environment because extracting materials like lithium, cobalt and nickel can cause significant deforestation and water pollution. The resources for these batteries are often found in vulnerable, developing countries, further highlighting the risks of exploitation. The mining process also raises ethical concerns because it has been linked to child labor and human rights violations, demonstrating that there are problems with the entire supply chain.

Lithium-ion batteries are expensive because making them involves complex processes, and the materials are costly to extract and refine. The increasing demand for electric vehicles (EVs) and renewable energy storage adds to their relatively high market price. The intricate manufacturing methods and stringent safety standards further contribute to their overall cost, making lithium-ion batteries less affordable, especially with the rising interest in EVs and renewable energy solutions in richer nations.

The increasing demand for EVs is causing concern, especially among communities facing socio-economic challenges, due to the limited global supply of critical materials required to produce lithium-ion batteries. S&P Global Mobility projects that EV sales will reach around 40–50% of total passenger car sales by 2030 in the United States. The growing popularity raises issues about the long-term sustainability of lithium-ion technology. It highlights the need to explore alternative battery chemistries that use more sustainable and readily available materials.

Beyond resource scarcity, there are also end-of-life challenges. Despite the evolving recycling methods for lithium-ion batteries, recovering materials still requires significant energy. This further accentuates challenges about the technology’s overall environmental footprint. Considering the drawbacks of lithium-ion batteries, it is crucial to invest in and explore alternative battery chemistries that address issues related to the environment, ethics, and resources. If we are to sufficiently foster an inclusive clean energy future, the well-being of vulnerable populations and landscapes must be prioritized as decisions on new technologies are made.

Innovative approaches to energy storage

Exploring alternative battery chemistries is critical to addressing the restraints brought on by current technologies. The environmental impact and supply challenges associated with lithium-ion batteries emphasize a need for innovative approaches to energy storage. Research must focus on discovering new battery technologies and chemistries that offer greater sustainability and cost-effectiveness while reducing environmental impact.

Researchers and innovators aim to uncover materials and processes that present unique advantages regarding resource efficiency, longevity, affordability, and ethical considerations by investigating beyond traditional lithium-ion. Innovation is at the heart of this exploration as it is the driving force behind sustainable energy solutions. Start-ups are already advancing battery technology and demonstrating creative thinking and problem-solving skills to shape a cleaner, more equitable, and more resilient energy future.

Mukesh Chatter Image: Alsym Energy, Inc.

Mukesh Chatter is the CEO and co-founder of Alsym Energy, a technology company developing a low-cost, high-performance rechargeable battery chemistry that is free of lithium and cobalt.

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Amidst the changing currents of U.S. energy policy and supply chain reform, the states of Nevada and Arkansas stand center stage in the development of lithium projects.

In a world increasingly defined by geopolitical complexities and economic interdependence, the United States finds itself at a critical juncture, navigating the delicate balance between energy security and global supply chain dynamics. The current landscape is one marked by strategic considerations and intentional policymaking.

In recent analysis, attention is drawn to a significant element: The incorporation of Foreign Entities of Concern (FEOC) within the Infrastructure Law. Notable nations covered by this provision include China, Russia, North Korea and Iran. This inclusion aims to curtail their influence in the burgeoning domestic battery supply chains.

Against this backdrop, the impending unveiling of the EV tax credit revolution in January 2024 and the enactment of the Inflation Reduction Act (IRA) in August 2022 emerge as catalytic forces propelling transformative shifts.

Just 16 months after the passage of the IRA, the largest federal investment in alternative energy and sustainability in American history, we are witness to historic climate action and an investment in America to create good paying jobs and reduce costs. Encouraged by the IRA, the private sector has announced over $110 billion in new clean energy manufacturing investments. over $70 billion in the electric vehicle (EV) supply chain and more than $10 billion in solar manufacturing. The private sector has invested in over $240 billion in new clean energy manufacturing investments since President Biden was elected.

Amidst the changing currents of U.S. energy policy and supply chain reform, the states of Nevada and Arkansas stand center stage in the development of lithium projects. Nevada, renowned for its arid landscapes and abundant natural resources, has become a crucible of innovation, hosting ambitious initiatives which harness the vast potential of lithium.

Nevada aims to become epicenter of lithium mining

Nevada Governor Joe Lombardo’s five-year strategic plan focuses on expanding the state’s electric vehicle production, technological innovation and new infrastructure. He believes that claystone lithium will emerge as the key critical element in Nevada’s energy transition as he seeks to make the ‘Silver State’ the epicenter of lithium mining in North America.

Unlike traditional lithium production from brine or hard rock sources, claystone lithium extraction represents a distinct approach that taps into the geological characteristics of regions in Nevada.

Arkansas’ role in powering America’s future

In the heartland of America, Arkansas is actively carving out its role in the energy sector by spearheading critical elements projects. A noteworthy development unfolded in November 2023 when ExxonMobil laid out ambitious plans to establish itself as a key player in lithium production. The company embarked on a significant venture by drilling its inaugural lithium well in southwest Arkansas, marking a strategic move toward bolstering the nation’s lithium supply. Under the brand Mobil Lithium, this endeavor underscores the transformative potential in regional initiatives.

These local initiatives are tangible examples of the groundswell of activity underway, attesting to the decentralized nature of the U.S. push toward energy independence and supply chain resilience.

The heightened need for the U.S. to source as much sustainable, “homemade” lithium as quickly as possible, with America’s natural resources and supportive policies able to bring new mines online, will ensure its place in history as the leader in America’s secure and sustainable new energy paradigm.

America’s road to energy metal independence is long and full of hurdles, both on the supply and processing side. While the United States holds about 8 million metric tons of lithium in reserve, ranking it among the top five countries in the world, right now only a fraction of the world’s supply is produced at one solitary lithium brine mine in Nevada called Silver Peak, run by Albemarle Corp.

As we dissect the intricate web of national policy, it becomes increasingly apparent that Nevada and Arkansas are not just states on the map; they are vital players in the quest to reshape domestic supply chains and elevate the nation’s energy security.

America’s legislative strides are engines of change, steering the nation toward a future characterized by a robust, self-sustaining ecosystem in the sourcing, manufacturing, processing, and recycling of energy metals. As the gears of progress are set into motion, America’s drive for domestic resilience is a paradigm shift actively reshaping the nation’s energy landscape.

Graham Harris is chairman and director of Surge Battery Metals Inc., a pure-play lithium company focused on its flagship project Nevada North Lithium Project in Elko County. He was previously founder, chair and director of Millennial Lithium Corp., which was acquired by Lithium Americas. Based in Vancouver, BC, Canada he can be reached at gharris@surgebatterymetals.com.

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Critical to the growth in renewable energy development, spurred by the passage of the IRA, is seamless documentation and data management while managing complexity, mitigating risk and maximizing returns at scale.

Long has the renewable energy industry waited for this moment: Riding the momentum of the past decade, dominant renewable technologies have reached cost-competitiveness with fossil fuels, and other emerging technologies that support the decarbonization of food, water, and waste are diversifying a quickly evolving and expanding market. And, of course, the Inflation Reduction Act (IRA) unlocked historic federal funding levels and established unprecedented legislative certainty for long-term industry support. Stronger and with more capital than ever, experts agree that the market is primed for rapid and explosive growth.

Critical to this growth will be project management software for renewable energy development that provides seamless documentation and data management while enabling banks, lenders, and developers alike to manage complexity, mitigate risk and maximize returns at scale.

But despite the clear need for innovation, traditional financial institutions have historically resisted adopting new technologies for project finance, opting instead to augment archaic legacy systems with spreadsheets, emails and PDFs. Bluntly put, this approach is short-sighted, inefficient, and expensive. These processes require too much time and manual labor from already slim teams while exposing counterparties to increased complexity and higher risk. In fact, a single loan can require 150 hours of unnecessary labor while also losing up to 70 bps.

Banks clinging to yesterday’s outdated tools will be woefully underprepared to scale efficiently for tomorrow’s challenges and profit from the market’s imminent growth, especially as assets become more distributed. With higher volumes of transactions comes higher mountains of paperwork that can critically delay a deal or wash away the margins with overhead.

The good news? Unlike the multifaceted issues of transmission infrastructure expansion or interconnection reform, this can be addressed primarily with technology: The industry can adopt a digital data management and risk monitoring strategy that leverages today’s automation and optimization technologies.

By bringing project finance tools into the 21st century, financiers can increase transparency and liquidity, tighten timelines and overhead, and reduce barriers to entry, fostering a flourishing, diverse, and scalable sustainable infrastructure market.

Need for better tools Historically, traditional utility-scale energy infrastructure deals have relied on a Frankensteined combination of multiple on-prem systems bolstered by webs of spreadsheets and other static documents. This translates to time-consuming manual processes, workflow redundancy, and opaque, disorganized data management.

Already highly cumbersome for managing large deals, this approach becomes prohibitively costly when investing in smaller distributed projects that have more data, contracts, and counterparties: The overhead required to finance a single $1 billion deal pales compared to the overhead required to finance 1,000 $1 million deals. A lack of deal transparency further stifles market diversity, as significant, entrenched players have typically been the only ones with the specialized industry knowledge to confidently assess project risk, track covenants and navigate other deal complexities.

While industry experts agree that the IRA’s legislative certainty and dedicated funding will undoubtedly accelerate market growth, the reality is that its tax credit, adder eligibility, and ongoing reporting requirements add multiple layers of complexity and risk that necessitate more organized and robust data management than what traditional tools can offer.

Other areas of finance have certainly benefited by adopting automation, digitization, and other advancements in fintech. In a recent industry report, over 35% of American businesses reported that payment automation saves their finance teams more than 500 hours per year on average. These same gains in efficiency and cost savings can be achieved across renewable energy project finance; in fact, one green bank will save over 1,400 processing hours across 30 reduced steps by replacing its manual systems with end-to-end software.

Three steps for growthWe’ve identified three steps that the sustainable infrastructure industry can take today to increase operational efficiency, decrease overhead, and accelerate deal velocity by adopting today’s technologies:

1.Initiate digitization today to build the foundation for future workflow automation.

Most challenges associated with today’s data management stem from siloed systems and the need for manual auditing, copying, and pasting. With a simple upgrade to centralized and digitized data management, organizations can prevent human error and minimize data inconsistencies and redundancies.

This simple step can not only lower the cost of capital and increase velocity and liquidity but also afford significant efficiency gains that accelerate market growth. For example, thanks to the digital data collection and automation afforded by fintech advancements, it now can take only minutes, instead of weeks, for a business to apply for and get approved for a commercial loan. Why can’t we do the same for project finance?

1. Create standardization to minimize risk and overhead, enabling a greater diversity of opportunities.

With a suite of tax credits that improve project economics for a wide range of technologies, the IRA is opening doors to more diverse opportunities within the sustainable infrastructure market – in particular, smaller deals in the 1 MW to 5 MW range are becoming more bankable. However, these opportunities are severely hampered by the bespoke nature of smaller projects that, combined with today’s inefficient processes and outdated tools, create barriers to investment in even the most low-risk, high-impact deals.

While complete standardization of sustainable infrastructure may not be possible today, some modularization of deal components can be achieved. By identifying similar components across deals, banks can decrease complexity and create greater predictability, which in turn can improve workflow efficiency and reduce perceived risk, lowering barriers and creating more opportunities for new entrants to participate.

1. Digitize compliance to take advantage of tax credits and manage ongoing requirements.

Today, Deal teams, often already small and overworked, must contend not only with increased volumes of opportunities but also with the mountains of data and documentation needed to track and measure eligibility for the IRA’s tax credits and adders. To be able to take full advantage of IRA benefits while also meeting requirements with auditable, organized documentation, the industry should increase transparency through centralized tracking and preparation of ongoing obligations.

In particular, a cloud-based data room can serve as a single source of truth, providing an infallible system of record and facilitating 360-degree visibility across all counterparties. This means that organizations can not only ensure an organized approach for evaluating and tracking tax credit eligibility with a clear digital audit trail of relevant documents but also hedge against future changes in guidelines and requirements.

Evolve today to scale tomorrowToday, more opportunities exist in the sustainable infrastructure market than ever before, and they are only predicted to grow in volume and diversity over the next decade. However, the industry’s slow adoption of more advanced, flexible, and accessible project finance tools will continue to limit deal velocity and increase barriers to entry, hindering the acceleration of market growth. To fully capitalize on C&I opportunities, the industry first needs to embrace existing technology to not only improve data access and management but also kickstart much-needed gains in operational efficiency, deal transparency, and standardization.

As we start to reap the benefits of the IRA, it will become increasingly urgent to evolve project finance management tools. Bolstered by advanced technologies, we can bring capital more efficiently and cost-effectively to a liquid, diverse and scalable sustainable infrastructure market.

Amanda Li, COO of Banyan Infrastructure, has over a decade of experience across sustainable infrastructure investing, management consulting in tech and finance sectors, and engineering. She leveraged experience from Generate Capital and McKinsey & Co. to co-found Banyan Infrastructure with CEO Will Greene in order to reduce the barriers for sustainable infrastructure financing through the company’s purpose-built project finance software.

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The interview process felt long and tedious and-- at times-- a bit like speed dating. But that is what is needed to find the right fit.

In the previous article in this series, I had spent a few months working with an architect on the first design stages of not your average dream home. This included positioning and azimuth of the home on the lot, a detailed interior layout, and other passivhaus considerations, such as exterior wall thickness, south-facing passive solar, air circulation, thermal mass, underground water cistern placement, and even an integrated indoor garden.

Now that I have these initial plans, since I am using a separate architect and builder, I am sharing them with builders to get quotes. Prior to the design process, I began searching for a builder through the Minnesota Green Path, which has a list of builders committed to energy-efficient residential home construction, including RESNET’s HERS (Home Energy Rating System) index and air exchange ratings.

I interviewed 13 builders from the Minnesota Green Path designated builder list. All of the builders were very knowledgeable on Minnesota’s Energy Code and often spoke about reducing the Air Changes per Hour (ACH), but many did not have the knowledge of or experience with the type of high-performance building principles that I am looking to achieve. For some builders, I needed to define the meaning of passivhaus. A German word, translated to passive house, that is a building practice of reducing energy demand (instead of offsetting it) through an airtight exterior, passive solar, thermal mass, and air exchange to maintain a comfortable temperature.

The interview process felt long and tedious and– at times– a bit like speed dating. But that is what is needed to find the right fit. As Justin Riddle from Paltrin recommends, “Interview different people and find what you think is a good fit for you at that moment. I always joke that it is a little bit like dating, you are about to get into a relationship with that company.” Riddle continued by explaining that a relationship with a builder will be a long-term one. While building may only take six months, the planning stages may take a year or more, and then there are questions post build for another few years.

During my first call with Riddle, I felt like I finally found my perfect builder match. He was the first builder who not only understood all the building practices that I wanted to achieve, but had implemented many of them. We ended up extending our thirty-minute phone call to an hour, geeking out about different types of energy efficiency and temperature control techniques – such a geothermal versus earth tubing.

Demonstrating his deep knowledge of sustainable building practices, Riddle explained “Some of the elements are the same wherever you are building, such as air quality, material choice or onsite power generation. In northern climates where the heating demand dominates, you can adjust the design to pick some passive solar heat via window sizing and glazing choice on the southern side.”

And being at the forefront of the sustainable building industry, Riddle noted that “there are lots of cool developments happening now where people are trying to advance materials, such as reducing the carbon footprint in concrete production, distribution models, and manufacturing methods using more modularity.”

Riddle, who has a PhD in Chemistry, is the founder and owner of Paltrin LLC, a boutique organization offering design-through-construction services, including energy analysis and mechanical design for custom home builds in the Twin Cities metro region.

“Our outcome is focused on delivering a home that our clients love. To do that we work with people wherever they are in their journey. Some people come to us with a blueprint and land, so we build a home for them. Others are more upstream from that so we get more involved in the design of the home and planning stages,” Riddle stated.

Previously in R&D at 3M for 14 years, Riddle transitioned into sustainable and energy efficient buildings after a chance encounter at a tradeshow when he learned about the USDA Biobased certification program. Now after seven years building sustainable homes, Riddle considers it his superpower where he can combine his formal scientific training with his love of construction to help people and society.

When it comes to sustainability and project scope, Riddle thinks about it on a continuum. “A sustainable home is working to minimize its ecological footprint, reduce operating costs, and provide a healthier, more environmentally responsible living space for its occupants. It’s about minimizing your impact now and in the future. This is typically achieved by working to minimize energy consumption, conserve water, use materials that are produced locally or with more renewable content, and to utilize renewable energy.”

During my first conversation with Riddle, I could tell he is as passionate as I am about high-performance buildings, and he believes that having this type of alignment between a builder’s motivation and clients is important. He also recommended a few certifications to ask about, including EnergyStar, Zero Energy Ready Home, and PHIUS (Passive House Institute US, Inc.) or PHI (Passivhaus Institut).

Out of the thirteen builders that I initially interviewed, four demonstrated some knowledge of the building practices I want to achieve so I’ve shared the preliminary plans from the architect with each of them, including Riddle. The quoting process for each is different, with all offering a square foot estimate for free and some also providing a more detailed quote based on subcontractor bids for free. Others have a fee of a few thousand dollars for the more detailed quote. While the free square foot estimate is nice to have, the detailed quote is necessary for the next step of understanding the budget and adjusting the design to fit the budget.

Riddle advised that the cost of building a sustainable home typically “does cost more upfront because you are likely selecting materials that are higher performing so they are more of a premium. In addition, there are generally more steps and details to pay attention to versus a code-built home, so there is more labor involved.” This can include working with municipalities and subcontractors who are not used to high-performance building practice and may require time and education. However, Riddle confirmed that the upfront cost tends to pay off in the long run, especially with higher inflation, which he said “seemed to surpass the cost difference of the sustainable features.”

With the quoting process from builders expected to take three to four weeks, I am eagerly waiting to hear back. In the meantime, I’ve been busy learning about soil health and regenerative farming with terra.do so that the house won’t just be net zero, but the land will be a carbon sink. Plus, I’ve been digging into the right roof angle and weighing a number of considerations that I’ll dive into in the next article.

Jessica Fishman Jessica Fishman is a strategic marketing professional with nearly 20 years’ experience, including seven years as head of global public and media relations at inverter maker SolarEdge. Passionate about addressing climate change by accelerating the clean energy transition, she has worked at leading renewables companies, building marketing and communications departments.

Read the first in the series Building not your average dream home.

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In a weekly update for pv magazine, Solcast, a DNV company, reports that North America in November experienced a divide in irradiance patterns across the continent.

From pv magazine global

Data analyzed by Solcast, via the Solcast API, shows there was unusually high irradiance in large swathes of Northeast North America due to anomalous high pressure that kept Atlantic moisture offshore. In contrast, the Gulf Coast received notably lower irradiance resulting from atmospheric shifts and cloud formation produced by the same high-pressure system.

The North-East saw clear skies, reaching irradiance levels up to 30% above the long-term November average. This was an unusually strong and widespread anomaly stretching from Oklahoma US to Quebec Canada. The driving force behind this high irradiance is the anomalous high pressure across the continental US that kept Atlantic moisture and resulting clouds from impacting solar assets located in these regions.

The Gulf Coast experienced cloudier conditions from Florida to the east coast of Mexico, with irradiance around 20% below the long-term November average. The anomalous high pressure system that brought increased sunshine farther north, induced lower pressure in the Gulf of Mexico, leading to increased atmospheric instability and cloud formation, reducing solar potential.

The Sierra Madre Occidental mountain range played a major role, shielding western Mexico from the Gulf’s moisture. The large disparity caused by the mountains can be seen in the average daily GHI data, with areas west of the mountains averaging 4-5 kWh/m2 across the month in clear contrast to the 3-4 kWh/m2 east of the mountains.

Despite the cloud-inducing impacts of the developing El Niño weather pattern along the US West Coast, a balance was achieved as the drying effects of the anomalous high pressure countered its effects. This pattern allowed solar asset operators on the US West Coast to still enjoy irradiance levels typical for November. However, further north along the west coast, the same high-pressure system diverted Pacific moisture away from the continental United States and towards British Columbia.

This redirection resulted in irradiance as much as 40% below the long-term average in British Columbia. Though significant in relative terms, this represented a small absolute reduction, considering the total solar potential in this region is only around 1 kWh/m2/day this time of year.

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.

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Affirmative arguments for how solar energy will offer tangible benefits like improving the local economy, providing landowners with a steady source of revenue through long-term rent payments, and lowering electricity bills can cultivate a good working relationship between the developer, landowner, and community.

Solar energy is opening more access to more people than ever as the United States strives to meet its attainable clean energy and climate change mitigation goals. Encouragingly, projections from the Solar Energy Industries Association (SEIA) and Wood Mackenzie suggest that the solar market is poised to triple by 2028, reaching an impressive 380 GW of installed solar capacity. That means delivering on clean energy goals for communities across the country. And it means energy reliability, access, affordability, education and leadership. It also means installing 938,220,000 solar modules throughout the United States over the next five years, according to the Department of Energy. Overall, communities with the solar industry accounted for 54% of all new electricity-generating capacity added to the grid in the first quarter of 2023.

With that much solar being installed, developers and communities are working hard to diversify the types of locations to build solar facilities. The diversification includes opening access to underutilized rooftops, parking lots, brownfields, timberland and farmland, including low-yield land.

Despite best efforts, landowners and developers often encounter significant opposition from local communities, who don’t believe distributed generation (DG) solar systems are a good use of the land. The concerns tend to be echoed from county to county, including viewscape, noise, traffic, property value, and environmental concerns. All are important to address and largely unfounded, but when left unaddressed, they can hinder getting a project implemented.

This is why strategic site selection is essential for solar developers in their quest for ideal project locations. Best suitable sites can become optimal locations that also positively impact the community. An additional benefit is that this can help mitigate opposition from the community.

Education deliversThough developers and landowners are steeped in the advantages of solar projects, they shouldn’t assume the community is. That’s why it can be effective to bring the community together early in the process and discuss the projects’ advantages for everyone.

These projects bring value, and different advantages can be emphasized depending on the type of project being developed.

• Solar projects are interim uses: the projects, which produce local clean energy with economic and environmental benefits are designed not to be permanent, and sites can be returned to previous use.
• Solar projects can enhance farm operations: For example, some solar arrays can be used to develop safe grazing areas for sheep and protect local pollinator populations, known as agrivoltaics, while generating electricity locally and easing the burden of high electricity costs.
• Soil erosion can be a significant problem on farmland, and research shows solar arrays help restore the soil. Solar with farming can help reduce the volume of fertilizer used, further protecting local waterways from the dangers of increased phosphorous.
• Putting solar arrays on former contaminated industrial sites, also known as brownfields, allows land with limited redevelopment uses to be repurposed into a project that serves the community through access to less expensive electricity generation.
• At a time when many communities are concerned about how much carbon they are putting in the atmosphere, solar arrays can contribute significantly to lowering those levels and improving the overall environment of an area.
• Commercial/community solar projects strengthen and modernize the grid in areas where such upgrades may otherwise be too expensive or impractical.
• Solar projects support education: Often, local schools provide opportunities for students to visit sites for hands-on learning about energy management, generation, land use, the grid, public policy and future energy distribution.
• Finally, solar facilities produce jobs and expand the tax base.

Making affirmative arguments for how solar energy will offer tangible benefits like improving the local economy, providing landowners with a steady source of revenue through long-term rent payments, and lowering electricity bills can cultivate a good working relationship between the developer, landowner, and community. Locally, the dollars invested and saved through lower electricity prices get recycled into the local economy, raising the standard of living for everyone.

Collaboration, Not ConfrontationEarly involvement by landowners, local residents and government officials can defuse oppositional attitudes in a community. Particularly in cases where permitting pathways include local preemption policies for power plant construction. It’s essential to hear the voices of the residents and their representatives to work together to eliminate roadblocks to the process.

By working together, local officials and residents can better accurately assess the effects and values a commercial or community solar project will have on a town. Collaborating offers opportunities to learn from each other and create advocates for the project within an area. Communities and local officials benefit from understanding the intricacies of any given site, including answers to questions like:

• What percentage of the parcel is dedicated to hosting the array?
• What dual uses can be built into the project alongside the solar array (agrivoltaics, rooftop shading) and other uses that benefit the community?
• What unusual soil conditions exist at a location? Will the soil need to be restored over time? Is fertilizer runoff a problem?
• For community solar projects, how many local subscribers will have access to clean energy and electricity savings who might not have it otherwise?
• What are the projected economic benefits?
• What’s the decommissioning plan?

Answering these questions and others that occur goes a long way toward building trust between the developer and the community—a vital step in reducing opposition and turning the project into a positive experience for everyone.

ImplementationIn any commercial or community solar project, developers must be strategic about their decision to site the project. Bring as many stakeholders on board as early as possible and adopt an attitude of collaboration rather than confrontation. Answering residents’ legitimate concerns can also build the trust necessary to smooth a project’s development from start to finish.

By following strategic siting approaches, developers can get more projects completed on time and within budget. Mitigating opposition will help communities build resilience in their electrical systems and enlist them in the larger mission to access reliable, clean and affordable energy for decades.

John Finnerty is director of business development at Standard Solar where he advances job growth and mentoring goals, focusing on growing local-generation markets in Maryland, Washington, D.C., Virginia, Delaware and beyond. Mr. Finnerty organizes expert engineering, construction, finance and operations teams to deliver innovative, market-leading solar and emerging storage projects for clients. His key to success is applying current public-policy benefits while advocating for policies that sustain market growth.

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In a new weekly update for pv magazine, OPIS, a Dow Jones company, provides a quick look at the main price trends in the global PV industry.

From pv magazine global

The FOB China prices of both PERC and TOPCon Mono M10 cells, the mainstream size of solar cells in the current solar market, continued their downward trajectory and were assessed at $0.0550 per W and $0.0616/W this week, respectively. This marks their lowest prices ever, according to OPIS data, amid falling prices of the entire supply chain and weak demand in China and its key export market.

Cell prices were negatively impacted by the ongoing price decline of the supply chain in China. Prices for China polysilicon and Mono PERC M10 wafers both decreased this week by 4.07% and 0.40%, respectively. The price of Mono PERC modules is approximately CNY1.011 ($0.14)/W, which is extremely close to the industry’s psychologically low value of CNY1/W, while the prices of TOPCon modules are slightly higher at CNY1.077/W.

OPIS learned from its market survey that cell manufacturers are making every effort to lower production costs as they are experiencing losses. One of the approaches is to buy wafers of reduced quality. According to a cell supplier, the Mono PERC M10 wafers with reduced quality are available on the China market for CNY1.7/pc while good quality wafers are still priced between CNY2.2/pc and CNY2.3/pc. This may resonate with a few downstream users who have been worried about the impact that this competition to cut production costs may have on module quality for 2024.

Another strategy for cell manufacturers to cut production costs is to outsource their production to original equipment manufacturers (OEMs). OPIS has learnt from the marketplace that a major cell manufacturer has an extremely high operating rate, as it has won numerous contracts from other cell companies that have outsourced their cell production.

According to OPIS’ market survey, manufacturers who outsource cell production benefit from the low cost brought by the high operating rates of OEMs, and could provide Mono PERC M10 cells at lower than CNY0.43/W in the China market. Those who continue to produce at low operating rates in their own production facilities are still offering it at around CNY0.45/W.

Sentiment in China remains bearish. According to the National Energy Administration, China deployed 13.62 gigawatts (GW) of solar in October, which presents a month-to-month decrease of 13.69%. This is the third straight month that China’s newly installed solar capacity has declined.

China’s key export markets continue to offer little sunshine. A state-owned cell manufacturing enterprise claims that sales of its cells have been hindered since the second half of the year, especially in the cell export market. Purchasing Chinese cells has become a rare occurrence for their Southeast Asian consumers, although formerly they did so regularly.

“The module producers cannot use Chinese cells if they want to ship their products to the US market; the local Southeast Asian market has a very limited solar capacity to digest Chinese cells and modules,” this supplier explained.

Looking ahead, the industry anticipates that the price of Mono PERC M10 cells will continue to decrease, with industry discussions suggesting that it may drop to approximately CNY0.4/W very soon in the Chinese domestic market. This indicates that the sentiment in the cell market will remain subdued.

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.

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The correlation between toxic emissions and cognitive impairment in the most vulnerable communities paints a sobering picture of inequality and environmental injustice. Yet, amidst this gloom, the electric vehicle revolution shines brightly as a beacon of hope.

The challenge of urban air pollution has emerged as a significant barrier to healthy development. In 2014, almost half of the American population resided in areas that fell short of federal air quality standards. This concerning trend correlates with a notable demographic shift noted by the Pew Research Center: between 2000 and 2014, urban regions in the U.S. saw a net gain of 1.6 million migrants, marking a move from areas with cleaner air to those more polluted.

The solution to improving urban air quality has been recognized within the scientific community since at least 1958, when a report in the Journal of Chemical Education contrasted the air pollution in Los Angeles ― with more cars per capita than any city on Earth ― and other major cities. The authors were confident that automobile exhaust was the main driver of urban air pollution for several reasons: the chemical composition of automobile exhaust, comparison of the estimated quantities of pollutants emitted by automobiles with those measured in the atmosphere, and distribution of traffic compared to the distribution of pollution effects. The report noted “the elimination [of air pollution] will depend on how much the citizens of Los Angeles and other affected areas are willing to pay for a remedy such as a device to be used on automobiles.”

Flash forward to the present. Emissions from transportation are the largest contributor of greenhouse gas emissions in the United States. According to the EPA, greenhouse gas emissions in the transportation sector increased more in absolute terms than any other sector from 1990 to 2021. Yet cities already have the solution. The miraculous “device to be used on automobiles” hypothesized decades ago is well-known today: engines powered by electricity, not gasoline, that eliminate tailpipe emissions altogether.

Years of research have also revealed the startling effects of toxic emission exposure on early childhood development, especially among non-White communities. The need for cities to reduce pollution is a moral imperative with clearly defined consequences for their most vulnerable residents:

• Children’s increased exposure to air toxins during infancy can delay brain development and reduce reading and math abilities. For some, the effect is equivalent to losing an entire month of elementary school.
• Pollution in the “most White” and “least White” census tracts across the United States is unevenly distributed. Nitrogen dioxide levels in the least White tracts were nearly three times higher than those in the most White, according to research published by the National Academy of Sciences. This is because many minority communities are jammed up against highways and major traffic corridors, often because of past redlining and highway construction cutting through their neighborhoods.
• According to the American Lung Association, if all new cars, pickup trucks, and SUVs sold by 2035 were zero-emission, there would be up to 89,300 fewer premature deaths, 2 million fewer asthma attacks, 10.7 million fewer lost workdays, and a savings of $978 billion in public health benefits across the United States by 2050.

Norway is often cited as a real-world example of how EV adoption can reduce air pollution. About 80% of new cars sold there now are fully electric, and another 10% are plug-in hybrids. The country is powered by an electricity grid that is already very green (91.8% hydropower and 6.4% wind). As a result, emissions of dangerous particles less than 2.5 micrometers in size plunged by nearly three-quarters from 2000 to 2020.

California’s ambitious EV adoption goals in recent years have yielded measurable results, too. According to a zip-code based ecologic study conducted in California from 2013-19, increasing the number of electric vehicles per 1,000 people by 20 in a given zip code was associated with a 3.2% drop in the rate of emergency room visits due to asthma ― a common side effect of inhaling combustion byproducts such as carbon monoxide, sulfur oxides, nitrogen oxides and aldehydes.

So, what’s a city to do? It can start by setting an example for residents by ditching gasoline-powered fleet vehicles in favor of EVs. These are cars, trucks, and buses that, by definition, conduct business within city limits. The growing number of fleet conversions at both the city and county levels appear to acknowledge both the problems associated with toxic automobile emissions and the obvious solution. The largest municipality in North America, New York City, already operates more than 4,000 government-owned EVs. The EPA’s Clean School Bus Program is providing more than $5 billion to help cities prioritize vehicles moving children and idling near schools.

Cities are also finding other ways to use taxpayer dollars to encourage EV adoption. In Los Angeles ― ground zero for harmful tailpipe emissions ― residents now enjoy more than 1,100 public charging stations, free parking and charging for EVs at some locations, and rebates for residents who install home chargers. In the San Francisco Bay Area, EV drivers receive reduced bridge tolls.

Advances in EV technology have been rapid enough over the last decade that cities and counties have no excuse not to meet the imperative of embracing EV adoption. In a world rapidly evolving toward urbanization, the menace of air pollution stands as a dark shadow, threatening the health and futures of our children. The correlation between toxic emissions and cognitive impairment in the most vulnerable communities paints a sobering picture of inequality and environmental injustice. Yet, amidst this gloom, the electric vehicle revolution shines brightly as a beacon of hope.

Cities are not just sprawling centers of economic growth and human potential; they also bear the responsibility of shaping the quality of life for millions. Every child deserves the right to breathe clean air, and every parent the assurance that their child’s environment isn’t silently eroding their potential. Data from places like Norway and California present not just a vision but a tangible reality of what is achievable.

As we stand on the cusp of technological and societal shifts, it’s no longer a question of whether cities can afford to embrace electric vehicles but whether they can afford not to. Let the drive toward an electrified future be the legacy we leave behind.

Kate L. Harrison is the co-founder and head of marketing at MoveEV, an AI-backed EV transition company that helps organizations convert fleet and employee-owned gas vehicles to electric, and reimburse for charging at home. With more than a decade of experience as a serial entrepreneur and seasoned marketer, Kate has worked with small businesses, nonprofits, and government organizations to make the world a better place. She is a best-selling author, thought leader, and frequent speaker at conferences and events, sharing her insights and experiences with others who are working to create a more sustainable future.

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A strategic and coordinated approach to integrate various clean energy solutions into the grid is vital to making space for the surge of renewables and electrification across the country, which is where "grid flexibility" enters the scene.

The global energy landscape is undergoing a transformative shift from traditional centralized grid networks to decentralized, distributed energy systems. At the same time, the U.S. is experiencing unprecedented grid load and supply growth shaped by ambitious net zero goals, supported by the Inflation Reduction Act (IRA) and the Bipartisan Infrastructure Law (BIL) and federal energy regulations like FERC Order 2222.

This evolution means we’re seeing huge market development and innovation, shown through massive proliferation of distributed energy resources (DERs), virtual power plants (VPPs), EVs, microgrids, small-scale renewables, distributed energy storage, and demand response solutions. A critical component for our net zero success and ability to modernize the aging grid infrastructure lies in understanding and embracing the concept of grid flexibility.

Challenging the norm

There has been $278 billion announced in new private clean energy investments, and $70B worth of grants, rebates, and other funding since the passing of the IRA. Despite this being a win for renewables, the surge in clean energy projects planned in the U.S. is outpacing the capabilities of many utilities and system operators (SOs), with a backlog of new interconnection requests hindering the process.

For these new low-carbon technologies to connect to the grid quickly and effectively, upgrades are needed to manage their additional impact (i.e., overloading circuits, voltage and frequency deviation) and variable generation patterns. On top of this, total electricity capacity in the U.S. is projected to double by 2050 to meet increasing electrification of industries, including heat and transportation, which leads to more strain on the grid than ever before.

A strategic and coordinated approach to integrate various clean energy solutions into the grid is vital to making space for the surge of renewables and electrification across the country, which is where “grid flexibility” enters the scene.

Defining grid flexibility

Grid flexibility refers to the ability to adapt quickly to changes in electricity supply and demand. Utilities have to continuously manage fluctuations in power generation and demand; flexible solutions, such as energy storage systems, help ensure renewables and new load can come online, while also reliably keeping the power on. For example, when there’s too much power on the system coming through from wind turbines on a gusty day, large-scale energy users could increase their energy usage.

If there’s not enough power, a storage system or aggregation of EVs can discharge to ensure there’s sufficient power coming through. By optimizing the deployment of renewables and DERs, grid operators can enhance the efficiency and resilience of the grid, reduce emissions, and achieve climate goals. Through embracing flexibility, utilities and system operators can also maximize systems already in place, avoiding costly grid upgrades and expensive gas peaking plants which are operated a small percentage of their potential uptime but will be stranded in an electrified future.

Localizing grid flexibility

Grid flexibility is not a new concept. The broad case for energy efficiency and demand response has been proven for decades now, and hundreds of programs are run across the country. However, the applications, types and sizes of DERs have changed dramatically in recent years.

Localized, rather than system-wide, flexibility is a major missing part of the flex equation. An increasingly electrified and decentralized grid will experience significant locational strains. One application for flexibility, non-wires alternatives (NWAs), has been a part of the U.S. energy grid for many years, but these programs are often inefficient, clunky, and not up to the job. But we can learn from the other countries who have already successfully implemented grid flexibility solutions that are easy-to-administer, open up new revenue streams for businesses, and ensure a smarter, more efficient energy system.

Implementing grid flexibility – U.S. case study:

We’re seeing that grid flexibility can lead to significant cost savings for both utilities and consumers. One great example of leveraging local flexibility for the NWA use case is Con Edison’s Brooklyn Queens Demand Management Program, which included energy efficiency, demand response, and distributed resources strategies that resulted in an estimated net benefit of $94.9 million. We need to build on these learnings and rethink how we incentivize the development of the grid and our energy infrastructure.

Looking to the future

Momentum is building for grid flexibility in the U.S. as the country aims to decarbonize and strengthen domestic energy security, and it’s clear the time has come to establish a flexible, secure, reliable, and environmentally conscious energy system for generations to come. Successfully achieving flexible, sustainable grids will require a focus on localization, innovative market platforms, and coordination across partners to solidify a clean energy future.

John Bayard is chief commercial officer of Piclo, an independent marketplace for energy flexibility services, enabling system operators to source energy flexibility from flexible service providers during times of high demand or low supply.

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The growing role that agrivoltaics can play in helping to significantly reduce energy costs and meet clean energy targets.

The seeds of change are being sowed in the agriculture industry. Climate change impacts, the need to feed a growing global population, rising energy costs, international conflicts, and shifting government policies and subsidies, are necessitating farmers and other stakeholders to look to innovative new technologies to adapt, and prosper, in this rapidly changing market.

Agriculture was one of the earliest industries to adopt solar photovoltaic (PV) energy. Rooftop installations on barns, sheds and other farm structures are used to generate free power for driving irrigation pumps and other critical systems or for selling to the local utility. However, agrivoltaics or agri-PV, where both a PV installation and agricultural activities coexist on the same piece of land, is increasingly seen as a viable solution for sustainable land use, without being detrimental to crop yields or solar production.

Twice the harvest

With about 14 GW of global capacity installed as of 2021, agri-PV offers the means to drastically reduce electricity bills with clean, renewable energy while increasing crop yields and balancing competing land interests. Dual-use farming occurs when elevated PV systems are installed on farmland where crops are cultivated, or where livestock grazes underneath. This method, also referred to as co-locating, can yield impressive results when done correctly and using the right technology. With dual-use farming, solar modules produce electricity, while providing optimal sunshine and shade for the crops underneath, reducing heat stress and water loss. This shade is also beneficial to livestock in the heat, and can help to protect them from harsh weather in winter too.

According to a study conducted by the University of Arizona, evaporation in tomatoes, peppers, cilantro and onions was cut by 50% due to the cooler temperatures below the panels. In turn, this meant irrigation could be cut by half, and temperature conditions for workers, or livestock if present, improved, with skin temperatures recorded as 20°F cooler under the panels. Similarly, a further Arizona study found that adding solar panels helped to moderate severe climate variability, helping to protect crops from weather related damage.

Research has also found that dual use aids the energy production of photovoltaic systems. NREL found that traditional ground-mounted PV panels were substantially warmer during the day than those with the plant-based understory. The agrivoltaic panels were found to be 48°F cooler, which allowed for better performance. This allows farmers to enjoy the cost benefits of increased energy production, as well as the higher yields of their crops, or better livelihood of their grazing stock.

The right technologies for the job

One of the major challenges to successful agri-PV lies in the effective planning of solar and agricultural projects. For the two ecosystems to work in tandem, smart, responsive PV technologies must be leveraged in order to maximize both solar energy harvesting and crop yields. That is why equipment selection is critical. As crops have individual light compensation points, and are extremely susceptible to weather, agri-PV installations should include specialized systems to support cultivation.

Elevated solar modules can reduce the impact of hail, wind, and heavy rain while producing shade to protect crops from overexposure to the sun and keeping the soil moist. In this case, it is critical to use the correct type of solar module so as not to overexpose or underexpose the crops growing underneath. However, changing the structures of the modules, or using modules which allow more light to shine through, may diminish energy production.

For optimal results, maximizing both the crop harvest and the solar energy yield is best achieved by installing a module level power electronics (MLPE) based PV system. This is because MLPE technology, such as power optimizers, enables each module to produce at its maximum energy level independently, regardless of module orientation or shade / dirt exposure.

An MLPE system with power optimizers paired with solar trackers can further help maximize both the harvest and energy yield. Power optimizers ensure that each module delivers the maximum amount of solar power possible. At the same time, the trackers use artificial intelligence (AI) to understand solar and agricultural seasonal patterns to tilt the modules as the sun moves in various directions throughout the day to boost power production.

Together, these key technologies allow for the optimization of both solar energy and crop growth, reducing levelized cost of electricity and maximizing the return on investment for the PV system owner while facilitating optimal conditions for agricultural cultivation.

In other cases, vertically mounted bifacial modules that can produce solar PV from both sides can be used to allow for more arable land. Here too, using MLPE technology with power optimizers, more power can be harvested from the installation. Power optimizers can also help mitigate power losses caused by module mismatch, which is not uncommon in bifacial modules, due to reduced surface albedo (the ability of the surface to reflect sunlight) and irradiance differences on the rear side of the module caused by increased levels of dirt and shading due to the ground proximity.

Livestock as a sustainable maintenance solution

Agri-PV also provides farmers with another major benefit: additional land for grazing livestock. Ground-mounted PV systems often require mowing contracts to keep the weeds and grass from overgrowing and reducing energy production. To keep vegetation under control, livestock can be used to graze.

When correctly managed, this model provides another win-win for both parties involved, as the herds benefit from access to feed, extra shade from the modules, and additional safety from predators due to secure fencing. In turn, the PV system owners and EPC contractors benefit from grazed pastures, reduced operation and maintenance costs from mowing, additional monitoring from on-site farmers, and strengthened relationships with local communities.

Protecting the land for pollinators

The most significant threat to pollinators is climate change and habitat loss, due to human conversion of grasslands for other land use. Some studies show that solar farms can have many benefits for bee and butterfly farmers, when designed with pollinator-supporting plants such as prairie-clover or other wildflowers.

About 25% of native bee populations in the U.S. are at risk of extinction, while monarch butterfly populations have declined about 68% over the past two decades. This is leading some ground-mount PV installation owners to introduce pollinator-supporting plants, critical to our ecosystem. Planning these in conjunction with local beekeepers and conservation specialists allows them to develop habitats that research and support bee or butterfly species over long periods of time.

Maximizing harvests

Through the advent of Agri-PV, the solar and agricultural industries can work together to make significant progress toward transforming food supplies and accelerating the transition to clean energy. When planned carefully, and in cooperation with local farmers, agri-PV offers smart solution to many of the challenges we face today, and can ultimately help to create a brighter future for our planet.

Ben Frank is senior director of National Commercial Sales at SolarEdge Technologies.

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A closer look at guidance on the Inflation Reduction Act domestic content adder.

It’s been over a year since the passage of the Inflation Reduction Act, a landmark piece of legislation designed to bolster U.S. clean energy infrastructure, manufacturing and adoption. The bill includes numerous incentives for U.S. solar production. These products are more attractive and cost-efficient than ever and we’ve seen new solar projects and manufacturing capacity announced at record rates over the past year as a result.

However, for some IRA tax credits and benefits, the qualifying factors remain unclear, opening up industry debate on how U.S. cleantech products and projects will be assessed throughout the rest of the decade and beyond. This includes the IRS’s proposed guidance on which renewable energy projects will qualify for an additional 10% domestic content tax credit.

In the solar industry in particular, this guidance gives an advantage to companies that have already committed to U.S. parts and labor for manufacturing and installation but there are also challenges and discrepancies that should be addressed before the guidance is finalized.

Potential challenges

The new guidance states that manufactured products qualifying for the added tax credit must be produced in the U.S. This means all manufacturing processes must be U.S.-based and furthermore, that all of such product components must be of U.S. origin. This guidance contradicts the Made in America Act, which calls for U.S.-based manufactured products to have a 55% of such product’s total cost to come from U.S. made components. This discrepancy should be addressed prior to the new guidance. It’s particularly important to have clear qualifications for solar products, where varied components and materials are necessary to manufacture and install modules.

On a similar note, solar glass and cells – two essential components for building modules – are currently not being manufactured anywhere in the U.S. Some domestic manufacturers work closely with a Canadian company that is planning to manufacture solar glass rather than turning to overseas manufacturers once they are up and running. However, that means their products would not currently qualify for the price to be used on the domestic adder but only the portion of the costs attributable to domestic components. This new guidance and the IRA overall is expected to attract more domestic manufacturing. It will be important that companies offering cells, glass and other underrepresented items are prioritized and encouraged to set up operations in the U.S. to help manufacturers achieve entirely U.S.-made modules that qualify for the 10% adder.

What’s Next

Regardless of what political shifts may be headed our way, U.S. solar manufacturing and installation won’t be slowing down any time soon. The business case for solar in this country is based on its strong and rewarding return on investment, meaning the industry will continue to grow and mature.

To support this continued growth, all U.S.-based clean energy manufacturing and development should be incentivized to use more domestic materials. Refining guidance found in the IRA, like the domestic content adders, should make U.S. manufacturing and sourcing easier and more lucrative over time as well. We can also expect the domestic incentive aspect of the IRA to help attract more solar component manufacturers to the U.S., particularly to fill the gap in domestic glass and cell manufacturing we currently see. In the meantime, solar manufacturers who are currently using a mix of U.S. and foreign-made components will need to disclose their entire cost breakdown for their customers to qualify for these credits. While this may be an unfamiliar requirement for some, it is ultimately a good thing – more transparent costing and hence pricing will encourage market competition.

Looking beyond manufacturing guidelines, companies expanding their U.S. solar operations need to also keep a close eye on wage requirements; many may need to pay workers the prevailing wage to qualify for funding.

All incentives included in the IRA will be beneficial to bolster adoption and awareness for clean energy technologies among consumers, manufacturers and local governments. One year after its passage is a perfect time to examine guidance like the domestic content adders to ensure it prioritizes strengthening U.S. manufacturing and supply chains for years to come.

Martin Pochtaruk has 35 years of experience managing manufacturing and innovation businesses across Europe and the Americas. He founded Heliene, a technology leading high quality solar PV manufacturer in 2010.

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Technological advancements are informing the way maintenance specialists are trained and deployed in the industry.

From all accounts, the EV market is exploding nationwide. Recent studies show that by 2030, the market is expected to hit $1.58 trillion. This exponential growth has led to the need for maintenance professionals uniquely trained and positioned to service EV cars and charging stations.

Because the EV market growth has been so significant, the rate of qualified infrastructure maintenance experts being trained and brought into the industry has struggled to keep pace. To meet the rapidly growing demand, there will need to be an increased focus on training maintenance professionals with specialized knowledge and skill sets for the EV market.

The need for certified experts

One of the main reasons for the overwhelming need for maintenance experts is the problem with EV charging stations evident across the US. Much like the number of skilled maintenance experts struggling to keep up with EV demand, the number of working and accessible EV charging stations has lagged, causing understandable frustration among EV drivers.

Many EV aficionados claim the issue of broken EV charging stations goes under-reported, causing rampant “charging anxiety” among EV drivers. They are not concerned with how many miles they can get out of a full charge, but rather if there will be a working charging station available when they need one.

The National Electric Vehicle Infrastructure (NEVI) Formula Program is aiming high with a goal to fund a large-scale deployment of charging stations to maintain a 97% operational uptime. The problem is that there are simply not enough certified and qualified professionals available to meet that uptime goal.

This lack of certified experts has created undue stress on the industry. With the market continuing to grow by leaps and bounds year after year, there will need to be a significant push to train and certify EV charging station maintenance specialists.

How to train

With the automobile market changing, the maintenance space will also have to shift. Technological advancements are informing the way maintenance specialists are trained and deployed in the industry.

The EV revolution has created an opportunity for those with electrician or auto maintenance skills to add to their abilities and create new career prospects for themselves. The EV industry has great potential for new job opportunities, according to the Bureau of Labor Statistics.

As of an October 2023 report, there are still too few technicians certified to work with EV vehicles or within EV infrastructure, with only 1.5% of ASE Certified technicians holding a certification for EV work. Those interested in the proliferation of clean energy and the continuation of EV technology will need to press for more training, better training, and greater deployment of trained technicians to keep up with the rate of EV adoption.

Artificial intelligence and virtual reality tools are emerging as an efficient and effective way to train the next generation of EV maintenance technicians. Through virtual reality training modules, technicians-in-training can learn by doing and practice complex repair approaches and maintenance tasks in a safe and immersive digital environment.

AI has proven to be a useful tool in evaluating the skills and knowledge base of electric vehicle technicians. Through AI assessments, those tasked with training these specialists can see where upskilling may be required and deploy the right technicians to the right areas of need.

Gamified training also helps EV technicians train for this new world of work, as gamification makes training and upskilling engaging and even fun. Through gamified training modules, technicians can master new skills and competencies that the EV market desperately needs if the infrastructure hopes to catch up with EV driver adoption.

Data is significant from a training perspective, and those who are training and certifying EV workers will need access to real-time insights, up-to-date knowledge, and the most advanced training materials to keep the skill levels up to speed with the industry’s rapid rate of change.

The future of EV adoption

Everyone from casual drivers to our nation’s government is taking the EV revolution seriously. The Biden Administration has spearheaded the installation of 500,000 new EV charging stations nationwide to be up and running by 2030. While this adoption of electric vehicles is promising, without trained and certified people to keep the charging infrastructure operational, the revolution may be dead in the water.

While finding a charging station in the United States will become easier as more stations are built on the heels of Biden’s push for better infrastructure, the operability of those stations is what matters. Without access to charging capabilities, people may abandon EVs altogether.

With emissions from gas-powered vehicles continuing to wreak havoc on the environment, it is important that the momentum of the EV revolution is maintained. Through training and certifying EV infrastructure maintenance experts, all of the good that electric vehicles have brought to the environment can continue.

Rue Phillips is president and co-founder of SkillFusion, a digital customer service platform for training, certification, and compliance of Electric Vehicle Supply Equipment (EVSE) Electricians, Technicians, and EV-ComTechs.

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Interconnection, or the process of acquiring a utility’s permission to connect to the local distribution grid, threatens to derail tremendous progress being made across the country to build out innovative types of energy, including community solar.

Across the nation, the distribution grid is deadlocked. While headlines discuss supply chain bottlenecks or inflate communities’ hesitancy to build solar and wind farms on their land, the largest reason for this deadlock involves interconnection.

Interconnection, or the process of acquiring a utility’s permission to connect to the local distribution grid, threatens to derail tremendous progress being made across the country to build out innovative types of energy, including community solar, that offer equitable access to clean energy. Queues around the country are flooded with applications that overwhelm utilities, and the backlog threatens states’ 2030 climate goals.

The good news is many reasons for the current delays have a tenable solution. State utility commissions can help solve this significant challenge by working collaboratively and by improving data transparency.

The significance of interconnection for distributed, renewable energy generation cannot be emphasized enough. A rapid and cost-effective grid connection is crucial for project success. Unfortunately, interconnection delays and unpredictable grid upgrade costs have slowed community solar project development across the country.

In Maine, over 400 MW of projects have been delayed for more than a year due to cluster studies. Some of these projects might never be built due to the magnitude of delays, unexpected upgrade costs on the order of millions of dollars, or both. Utilities in states like Virginia, Delaware, and Maryland have overly broad technical planning limits that restrict where community solar can go, or that require prohibitively expensive protection equipment, known as Direct Transfer Trip, without considering alternatives.

A 2022 analysis estimated it would take 260 years to clear Minnesota’s interconnection backlog at Xcel Energy’s current pace of review. These serve as just a few examples displaying the prevalence of interconnection issues throughout the country.

Volume of applications

A major reason for delays is the sheer volume of interconnection applications utilities receive. Community solar offers an array of benefits, like reducing emissions, increasing energy equity, and improving grid resiliency. Additionally, federal policies are accelerating deployment through the EPA’s Solar for All fund and the Low-Income Communities Bonus and Investment Tax Credits.

As a result, newly opened programs often incur a flood of applications. Delmarva Power received over 250MW of interconnection applications over a two-day period when Delaware’s community solar program opened in 2021. The number of interconnection applications in Massachusetts nearly doubled in the three-year period following the launch of its programs. New interconnection applications can also overwhelm utilities that have not modernized and streamlined their review processes.

However, even for utilities that have taken important steps to improve the interconnection process, many still can’t manage the flood of application requests. Part of the influx problem is that many of these applications are for “zombie projects.” A “zombie” project is a project that turns out to be infeasible to build — often because of information that the developer couldn’t have known without submitting an interconnection application in the first place.

Most utilities provide very little actionable information about the best interconnection locations on their distribution system in advance of submitting an interconnection application. As a result, project developers must rely on the interconnection application process as a prospecting tool, seeking to test out — through trial-and-error of application submissions — which grid locations might be suitable to interconnect. Any project could be viable, but the developer simply doesn’t know until they apply for interconnection.

Zombie projects

The end result is that interconnection queues are full of test project requests that ultimately aren’t viable — affectionately referred to within the industry as “zombie projects.”

The best way to get rid of zombie projects is to ensure project developers have the right information to put forward a well-founded interconnection application. Utilities and regulators can help drive this change in several ways. First, they can be required to publish hosting capacity maps that contain distribution asset information and are updated at least monthly. While many states now require utilities to publish hosting capacity maps, these two pieces of information ensure the maps are useful and up to date. Good examples of this exist in California, Massachusetts, Minnesota, and Oregon.

Regulators can also ensure that interconnection queues are made publicly available. Substation and feeder names, application status (including withdrawals), interconnection cost estimates, and proposed in-service dates are especially useful details to include. Examples of states and utilities that provide this information today include Duke Energy, Hawaiian Electric Companies, Massachusetts, New York, and Xcel Energy.

Well-designed hosting capacity analyses and interconnection queue reports can significantly reduce the number of speculative interconnection applications. This is readily available information, and making it public would reduce the utilities’ duplicative efforts and workload, which is funded by ratepayers. Regulators should require utilities to adopt these best practices for the benefit of utility customers, and because states’ clean energy goals depend on it.

As the number of distributed energy resources blossom — including but not limited to community solar projects — these new installations will continue to seek to interconnect to the distribution system, and this kind of data transparency will be critical to keep the zombies at bay.

Sam Weaver is the interconnection and grid integration policy director at the Coalition for Community Solar Access (CCSA).

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Recent thermal events have demonstrated that to benefit from these systems, we need to ensure that there is a greater understanding of potential issues that should be considered with BESS installations.

Skim through any power and energy publication or platform and you’re likely to see the topic of battery energy storage systems (BESS) hovering above the fold. It’s an important—if not polarizing topic–as hundreds of millions of dollars in U.S. funding are released to enable renewable sources of energy. As technology continues to outpace required upgrades to the power grid, how we store this energy becomes a priority of increasing importance.

There are many benefits to installing battery energy storage systems. In addition to assisting the grid with demand and frequency response, BESS can also provide backup power during outages and reduce the cost of electricity by using stored energy during times of peak usage when it is the most expensive.

These benefits, along with the proliferation of alternative energy sources, such as wind and solar, are driving the heightened interest in BESS. However, some recent thermal events have demonstrated that to benefit from these systems, we need to ensure that there is a greater understanding of potential issues that should be considered with BESS installations.

Recent thermal events

Between May and August of 2023, as summer was claiming its status as the hottest meteorological season on record, three BESS facilities in New York State were the subject of thermal events. The events involved four lithium battery storage units at the Chaumont Solar Farm in Jefferson County, two battery storage units in Orange County, and a 5 MW BESS facility in Suffolk County. While each event was contained without injury or extensive damage to the surrounding area, Jefferson County residents were ordered to shelter-in-place for several hours. Even as investigations into the cause of the events ended, public concerns remain.

There is a fundamental need to better inform the public about BESS installations. Each system is unique, and the most critical components are the batteries themselves. As the number of installations increase, it’s more important than ever that both elected officials and the public understand potential hazards associated with each installation, so they can ensure that these critical systems are properly designed and sited to effectively support their communities.

Potential BESS hazards

Radiant heat: When battery energy storage facilities are installed in close proximity to structures, combustible vegetation, or public transportation, radiant heat from a thermal event can present a risk to property and/or disrupt transportation. However, the actual impact of radiant heat during a thermal event can be calculated and these calculations are used to determine safe distances when siting these facilities.

Airborne contaminants: Some of the products of combustion from thermal events may be considered hazardous. This is true for BESS installations, as well as most other fires. It is important to understand the specific hazards for each installation, which will allow a safe perimeter to be established during a thermal event. This perimeter will protect emergency responders without creating undue shelter in place warnings.

Groundwater contamination (leaching): Concerns around the leaching of hazardous materials into the ground during a failure include the introduction of fire water. Fire response to a BESS thermal event can involve the application of significant volumes of water, which does not allow for the collection and treatment. It is important to understand what liquid constituents are released in a thermal event and whether they are soluble.

Decommissioning: Objections raised around decommissioning or plans to remove facilities at the end of their lifecycle, are easily addressed through prefunded demolition and thorough commissioning plans.

Understanding current codes/standards

The following codes and standards are used to regulate BESS installations in New York State and can serve as an example.

• 2019 Energy Storage System Supplement (Amendment to NYS Uniform Fire Prevention and Building Code)
• NFPA 855, Standard for the Installation of Stationary Energy Storage Systems
• UL 9540/9540A
  • UL 9540 provides a standard for the design, construction, testing and use of energy storage systems.
  • UL 9540A outlines the method for evaluating thermal runaway events in BESS systems. The large-scale fire testing performed in accordance with this standard provides critical data that can assist in the assessment of hazards and response to AHJ/Public comments and concerns.

Hazard assessment & best practices

BESS systems can vary dramatically, but the New York State Code and reference standards that regulate them are a one size fits all approach. This makes the site-specific hazard assessment critical to successful approval of each system. These assessments should be prepared by licensed professionals and provided for every BESS installation. They outline the hazards of each system and should be the basis for a jurisdictional review and approval.

While there is no substitution for a site-specific hazard assessment, the following are some approaches we have seen implemented in response to AHJ/public comments during the approval process along with some suggested tasks that can assist in reducing the potential for system safety issues arising:

• Pre-construction design reviews – Performing more rigorous assessments of the overall electrical system design including BESS, wiring, protective devices, etc. to ensure that are safe and fit-for-purpose.
• Fire Walls – Where code prescribed setbacks to combustible materials are not achievable, non-combustible rated walls can be implemented.
• Dry pipe fire suppression system – Implemented to provide emergency responders with a method to apply water to the exterior of BESS systems–while maintaining a safe perimeter–these systems work well when fire walls are required. The fire wall protects adjacent property, but it does impact the ability for the Fire Department to respond and apply water.
• UVIR (Ultraviolet Infrared) Detection – An effective supplement to fire walls, UVIR can provide early detection and FD notification, especially when the fire event starts outside of the BESS unit itself.
• Installation inspections – Performing more detailed inspections during various project phases, including pre-commissioning, final inspection before energization, post-energization thermal/visual inspections, regular operational inspections in addition to online monitoring.

Anticipated code/permit changes and outcomes

The outbreak of fires at three different BESS facilities has led to the reevaluation of industry safety procedures. New York State Senator Mark Walcyzk has called for a freeze on building new BESS projects until a full investigation is conducted. In response, New York’s Governor Hochul announced that large-scale energy storage facilities across the state will be inspected to ensure compliance with safety regulations. Additionally, Hochul created an inter-agency Fire Safety Working Group that includes NYSERDA, OFPC and the Department of Public Services (DPS), and LaBella Associates’ Building Code & Life Safety Services team. Together, we’ll work to establish best practices and help standardize the review and approval of BESS systems.

Ed Larkin is PE, regional manager, buildings engineering with LaBella Associates, an architecture/engineering firm located in Rochester, New York.

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The Inflation Reduction Act is opening the door to new business models that will dramatically accelerate the development of community solar and the benefits it provides to consumers, while also simplifying the process.

Solar is surging one year after President Biden signed the most significant climate bill in U.S. history into law. This is particularly true for community solar, which the Inflation Reduction Act (IRA) effectively enshrined in federal tax policy for the first time.

As a result of the IRA, unprecedented incentives mean a flood of new projects are likely to get off the ground in states that have a regulatory structure in place. But more importantly, the law and the rules for implementing it are opening the door to new business models that will dramatically accelerate the development of community solar and the benefits it provides to consumers, while also simplifying the process.

New partnerships between tech companies and solar developers will help drive new national subscription models that prioritize direct community investments and benefit low-and-moderate income (LMI) households. In addition to helping technology companies meet their clean energy goals, these new pairings will accelerate clean energy deployment in a way that delivers utility bill savings to low-income households who disproportionately suffer from high energy burdens.

While this is just one example of the innovative new partnerships that we expect to see take off because of the IRA, cross-industry collaborations are the future of the industry and will play a vital role in the continued expansion of community solar.

The result of these collaborations will be a leaner, more efficient, and more impactful industry that is poised for major growth for a variety of reasons.

For one, because these partnerships don’t require each state to authorize a community solar program through legislative action, they allow community solar access in jurisdictions across the entire country.

Because community solar projects are relatively small, and the IRA caps the project size at 5 MW, they can be built more quickly than utility-scale projects.

The process is also streamlined. Because the final IRA rules sync up with the processes that are already widely in use – including income verification rules, savings calculation methodologies and subscriber allocation processes — it will be easier for households to see savings in an immediate, easy-to-understand process that is simple to administer.

Additionally, reducing bureaucratic red tape and expediting project timelines will give developers the certainty they need to invest.

By incentivizing smaller-scale projects, we can circumvent the obstacles that have historically bogged down large renewable energy projects. This will help enable distributed generation systems, which are smaller-scale facilities located near the point of use compared to more traditional power plants and can be deployed much faster, to be a solution to the bottlenecks, and longer wait times and backlogs for clean energy project developers and that jeopardize clean energy targets.

Using distributed generation also shores up grid reliability and avoids the need for new transmission lines, which are similarly facing lengthy approval delays.

The result will be a stronger, more resilient and cleaner electrical grid that will help meet the nation’s renewable energy goals.

Next year is poised to be bright for the industry. Following a sluggish 2022, community solar installations are scheduled to gain momentum for the rest of the year and grow at a steady pace in the years ahead.

This growth also comes at a time when the Biden administration is seeking to expand awareness of the solar opportunities made available as part of this landmark legislation.

As we are seeing with just this first example, new federal rules and opportunities for new partnerships will only further turbocharge our industry. Innovative partnerships and new business models will continue to simplify what has historically been a complicated process and provide the framework for liftoff, offering new opportunities that allow our industry to continue to enter uncharted new heights.

Kiran Bhatraju is the founder and CEO of Arcadia, a company that builds utility data technology to serve consumers in the community solar market.

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The second in the series of building a sustainable dream home led the author on a search for the right architect and builder during which she ran into a few challenges.

While I was looking for a plot of land to build not your average dream home as described in the first article in this series, in parallel I was in search for the right architect and builder. Since I had been dreaming about and researching different types of sustainable homes for years, I already had a fairly detailed idea of what I wanted to build. But since I am no expert, I was in search of professionals who could implement my vision and improve upon it.

When I was evaluating land, I tried to take into account some of the requirements for my design concept, such as orientation and shading, but I was advised against designing the house before I found a piece of land. This is one of the first differences in building a sustainable home versus a standard house. Unlike a standard-built house that is solely designed to separate us from the elements, “a sustainable home requires that it be in harmony with its context and environment,” explained Josh Oqueli, owner of Bonsai Design Build.

During my search for the right architect and builder, I ran into a few challenges. The first was that while energy-efficient, sustainable homes would be one of the best ways to reduce energy demand, dependency on the grid, and carbon footprints, there are not a lot of experts out there. That’s because the architecture and construction industries are relatively conservative – professionally speaking.

Often when I described the concepts that I wanted to deploy, such as passivhaus, thermal mass, or biotecture, many architects and builders would resort to talking about structural insulated panels (SIPs) – which addresses only one element of the much more sophisticated way that I wanted to achieve sustainability and high performance. That’s because, as Oqueli explained, “Most architects have a working knowledge of sustainable building practices. Few have a command of high-performance building principles and even less know about biotecture practices.”

Another common hurdle that I ran into was finding experts who would meet my design and budget considerations. For instance, many did not want to build a smaller house, while others specialized in top-end houses. And I wanted to work with someone who believed that not only the ultra-wealthy are deserving of sustainability. That’s when I found Bonsai Design Build, a Denver-based certified-passivhaus designer and builder that offers turnkey solutions, from napkin sketch through certificate of occupancy.

With a dedicated team of six, they offer full services in the Denver metro area and architectural-only services throughout the country. When reviewing the company’s website and credentials, the Morrison Earth House in its portfolio jumped out to me as it incorporated both the passivhaus and biotecture design concepts that I wanted, such as a south-facing greenhouse, a building envelope, and rainwater catchment.

The design of this house was inspired by Michael Reynolds Earthships, which Oqueli describes as “the most revolutionary… and zenith of good architecture [because these homes] are designed to not only shelter life but also sustain.”

Without knowing it at the time, by focusing on the company’s completed projects, I was already following my future-architect’s advice for finding a design-build professional as he later said, “Certifications are good, but practical experience is usually better. It is a steep learning curve to command high-performance building principles and even more difficult to put them into practice.”

And so, I reached out to Josh Oqueli, owner of Bonsai. Oqueli has been an architect for 19 years, but 10 years ago he founded Bonsai because he thought “our buildings and the built environment at large is in desperate need for good architecture,” which he defines as keeping the elements out and looking and feeling good.

Speaking about the industry’s current design and structure problems, Oqueli explained, “The way we currently design and build structures is not in harmony with the Earth on multiple fronts. Most homes are designed to last thirty years, just enough to withstand a conventional mortgage timeframe. Our current code structure established a bare minimum threshold for human habitation. The industry at large has migrated towards liability avoidance and cheap building practices. All of these factors combined have put us in a precarious place where a large part of our building stock, I’d say 90+%, is hugely energy inefficient and barely habitable.”

When describing what is needed to change this dynamic, Oqueli explained “Conscious people who are willing to break the conventional mold and do what is right to elevate the harmonious buildings, which will in turn elevate the human spirit.”

That’s why in his practice, Oqueli brings a multidisciplinary skillset to the table, such as a solid understanding of high-performance building science, golden proportions, universal laws, and human consciousness.

When Oqueli and his team look at designing and building a sustainable house, they look at it on a spectrum and based on what the client’s commitment is to sustainability – from building practices to high-performance building principles and all the way to biotecture. But he says that the biggest misconception about building a sustainable house is that it needs to be net zero. He clarified that “net zero can be easily achievable because the building is high performance.”

“Successful application of [passivhaus building principles] will yield a low energy use building that can harmoniously integrate with its environment. A conventional home will consider code requirements, ignore its context, and strive for construction economies.”

Because a significant amount planning and thought is put into the design process of a sustainable house, there tends to be more upfront investment during the process – both in terms of time and budget. For instance, Oqueli explains how this means designing differently for various climates, “In colder regions, the need is to harness the sun and keep that energy within the building. In hotter regions, we need to shelter the building from the sun’s intense energy while creating natural ventilation. Completely different strategies in building envelope assembly, mechanics and if delving into the biotecture dimension.”

But these upfront costs pay off in the long run with high-performance building techniques leading to lower ongoing costs, potentially even negative, and as Oqueli emphasizes that is the definition of sustainability.

After working with Bonsai for a few months, going back and forth to optimize the intial design both for sustainability purposes and my personal vision, they have taken my napkin sketch and drastically improved it by combining both art and science, and turned it into an actual plan. While Bonsai offers full design and build services, since I decided to build in Minnesota due to climate collapse concerns, my next step is to find a local builder that has the skills, experience, and passion to turn this plan into not an average dream home.

Read the first in the series Building not your average dream home.

Jessica Fishman Jessica Fishman is a strategic marketing professional with nearly 20 years’ experience, including seven years as head of global public and media relations at inverter maker SolarEdge. Passionate about addressing climate change by accelerating the clean energy transition, she has worked at leading renewables companies, building marketing and communications departments.

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Central inverters still dominate the U.S. utility solar market but string inverters are beginning to get more traction in 10+ MW projects.

If you look back just twenty years in the U.S. solar industry, 1 MW was the total amount of solar being installed on an annual basis. Now, in 2023, the U.S. market may exceed 30 GW in one year! As megawatts have grown to gigawatts the inverter market has diversified and matured, but bigger inverters aren’t necessarily the growing trend. Central inverters still dominate the U.S. utility solar market but string inverters are beginning to get more traction in 10+ MW projects.

“…When a central inverter goes down for anything more than minor maintenance, it takes down several MWs of generation potential with it. The prolonged downtime for repair or replacement can be detrimental to project performance,” said Jason Ellsworth, CEO, Clēnera

Earlier this summer, Clēnera, a Boise, Idaho-based solar developer and asset manager began commercial operation of Apex Solar, a 105 MWdc solar project in Beaverhead County in southwestern Montana. The project is contracted to NorthWestern Energy under a 20-year power purchase agreement and is expected to generate carbon-free power equivalent to the annual consumption of 13,500 households. Unlike most of Clēnera’s previous projects that use central inverters, the Apex Solar plant is utilizing 275 kWac string inverters made by CPS America. 

Advantages of string inverters include their relatively small size and weight, the ability of the project owner to store spare replacement inverters on-site, and the lower production losses when an inverter goes down.

According to Jason Ellsworth, Clēnera co-founder and CEO,

As a company, we are aggressively seeking innovations that improve reliability. At Apex, string inverters are just one of the steps we’ve taken to ensure maximum reliability and performance. As a long-term owner and operator, we care deeply about the lifetime performance of each project.  We will continue to find ways to improve reliability, enhance performance, and extend the lifetime on all our projects.

In the dynamic landscape of the utility-scale solar market, which is anticipated to reach 23 GW of deployment in 2023, agility is paramount. In a recent interview with the CPS America’s leadership team at RE+ in Las Vegas where 40,000 energy professionals gathered, Bryan Wagner emphasized CPS’s “Lightspeed system” that bridges communication across its diverse departments, from R&D to sales to service. This nimbleness, he argues, translates to annual product evolutions, moving CPS’s inverter market share from a modest 2-3% five years ago to their current market share of 8%.

In 2016 GTM predicted that string inverters would achieve 20% market penetration in U.S. utility solar by 2022. Globally, the penetration of string inverters into utility solar is already 50% according to some sources.

According to CPS Global, string inverters are adopted at 80-90% of all their projects in some European & Asian countries.

“The Apex Solar Farm project is a testament to CPS‘s commitment to integrate the benefits of string into utility scale projects like Apex Solar and we couldn’t be more excited that Clēnera put their trust in CPS America on this project,” said Bryan Wagner of CPS America.

Tim Montague leads the Clean Power Consulting Group and is host of the Clean Power Hour podcast. He is a solar project developer, cleantech executive coach and consultant, mastermind group leader, entrepreneur and technology enthusiast.

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True energy equity requires that everyone have the opportunity, knowledge, and access to participate fully in the regulatory process.

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Three industry professionals traveled 3,000 miles across America. Their mission: to dissect their carbon footprint. What they found was a complex calculation, with results more tightly-knit than anticipated – and a CO2 revelation.

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The incentives in the Inflation Reduction Act are combining with an evolving distributed generation market and investors' greater appetite for community solar to drive an uptick in renewable project financing and deployment.

If you’ve tried to secure financing to develop a community solar project in recent years, you know options were limited. Banks and lenders often expressed skepticism over the returns from subscription-based renewable energy sources and were uncomfortable with the risk they provided.

But given the Inflation Reduction Act (IRA) that was signed into law last summer, things are looking up. The act’s incentives, including tax credits and direct payments, are combining with a continuously evolving distributed generation market and investors’ greater appetite for community solar to drive an uptick in renewable project financing and deployment.

According to Wood Mackenzie, the U.S. community solar market is projected to grow 118% over the next five years because of the optimism surrounding the IRA. That would come despite a 16% decline in installed capacity in 2022 because of supply chain constraints and interconnection delays.

To tap into this newfound investor interest, maximize the act’s provisions, and enable greater access to community solar, developers must come up with creative deal structures and partnerships.

Unlocking clean energy growth

The IRA represents the federal government’s most significant investment in renewable energy production to date — and it will transform how we power this country.

All told, it devotes nearly $400 billion to clean energy generation through tax incentives, grants, and loan guarantees. It sets the Investment Tax Credit (ITC) at 30% through 2032, allows ITCs to be transferred to unaffiliated taxpayers, and includes bonuses that encourage domestic manufacturing, energy storage projects, and developments in underserved areas like tribal lands and low-income communities. Not only will these incentives drive project development and increase clean energy access to areas that need it the most, but it will also make projects a lot more economical, pushing more and more developers, independent power producers (IPPs), investors, and asset owners to enter the market.

Conveniently, this policy shift comes as community solar is rising as a reliable energy alternative. It provides the benefits of clean energy to subscribers, broadening access to solar energy among residents, businesses, and other organizations that are unable to host their own solar energy systems on-site.

Community solar’s surge in popularity is spurring investor interest and leading to more confidence in project viability. And as subscriber retention remains high, banks are more willing to expand lending for these types of projects, thereby making them less costly to deploy.

Better project economics and more market players drive even greater production and demand for these projects.

Creative financing

So, what are some of the emerging ways developers can get community solar projects financed in this shifting environment?

One important consideration for successfully deploying community solar projects is to secure flexible capital, which minimizes the burden on cash flow. By nature, flexible capital providers often have a higher risk tolerance, and they’re increasingly willing to create specialized debt facilities or carveouts that allow for traditionally non-investment grade exposures — like a community solar project. As interest grows for these types of projects, the need for flexible capital should expand as well, allowing developers to deploy a larger amount of diversified assets.

In order to increase accessibility, developers must consider new vehicles for financing their deals, and how they are structured. More unconventional financing methods for solar, such as an asset-backed securitization (ABS), can leverage a broad portfolio’s proven operational history to secure financing for upcoming projects by using those assets as collateral. Going the ABS route is largely untapped for financing commercial solar projects, especially community solar projects, but can be most efficient for deploying a large portfolio of diversified projects.

Developers must also consider taking new approaches to the way these deals are structured. Some have started to leverage new and alternative metrics for determining community solar subscriber eligibility. Traditionally, community solar projects have used quantifiable metrics, such as FICO scores, to determine subscriber eligibility, which often results in the exclusion of low-to-moderate income groups. By shifting eligibility metrics to take into account things like default rates, projects become more accessible to a wider range of subscribers. The first-of-its-kind ABS deal for community solar, which was structured in this way and utilized these non-traditional metrics, was just closed in late 2022, and it’s only the tip of the iceberg.

It’s no secret that securing funding for projects in the renewables space has always been a bit difficult, but improved project economics from the IRA, and increasing appetite for community solar, will make securing flexible capital and these new financing structures increasingly more viable.

What developers may find most valuable under the IRA is that tax credits can now be used as bargaining tools that help get projects off the ground. Banks have more taxable income than most developers, so they may take on at least a portion of the ITC in exchange for funding community solar projects — an outlay that very well may be less than the tax credit’s value.

Customized arrangements

Looking ahead, community solar’s growth will rely on developers leveraging these approaches to innovative project financing in order to increase solar access and take full advantage of what the IRA has to offer. But they need to keep in mind that this can only be achieved by focusing on building and maintaining strong relationships with banks, lenders, and other equity partners, especially those with an appetite toward supporting community solar.

By fostering these relationships and leveraging the provisions of the IRA, developers will enable broader access to solar energy for years to come. We’ll start to see a greater frequency of community solar, with more projects on tribal lands, in rural and coal communities, and among underserved populations.

The sky’s the limit — and by tapping into this shifting financial landscape for renewables, we’ll light the path to bringing much-needed solar energy to communities across America.

Akash Patel is the VP of underwriting for DSD Renewables and leads evaluation of project and investment opportunities across DSD’s pipeline. While with DSD, Akash has supported multiple capital raises and project financings, ranging from debt to structured equity transactions. Akash began his career at CIT where he was trained in their aerospace and defense group before joining their power and project finance division. Prior to DSD, Akash was at H.I.G. WhiteHorse where he supported high yield debt and equity investments in private, sponsor-backed transactions. Akash holds a B.S. in Finance and Economics from Rutgers University.

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As the renewable energy industry adapts to a new normal, the NOPR outlines a more pragmatic path to compliance than many in the industry had feared based on Treasury’s Initial Guidance.

Payment of a prevailing wage to workers and employment of apprentices are key requirements for renewable energy developers to obtain the various tax incentives for their projects provided by the Inflation Reduction Act of 2022 (“IRA”). A little over a year following enactment of the IRA, and nine months after release of the initial guidance, on August 30, 2023, the Treasury Department and IRS released the Notice of Proposed Rulemaking (“NOPR”) on prevailing wage and apprenticeship requirements.

The November 30, 2023, initial guidance (“Initial Guidance”) still governs prevailing wage and apprenticeship requirements, but the clock is ticking: taxpayers may rely on the NOPR beginning October 30, 2023.

(Read: “The clock is ticking on the IRA’s prevailing wage and apprenticeship requirements“)

The NOPR provides useful clarifications and additional details helpful for taxpayers evaluating their project compliance strategies but still leaves certain details open to interpretation. The NOPR is, of course, not the final regulation, but it is an additional step in the rulemaking process open to comments from the public.

Overall, the NOPR is consistent with the Initial Guidance (outlined in our article here), with key updates outlined below.

Prevailing wage and apprenticeship requirements apply to all “construction, alteration or repair” of a qualified facility, and continue through any portion of a taxable year within the 10-year period beginning on the date the qualified facility is placed in service. But the NOPR provides a key clarification for plant operations: it specifies that “construction, alteration or repair” does not include “work that is ordinary and regular in nature that is designed to maintain and preserve existing functionalities of a facility after it is placed in service.”

It provides examples of basic operations and maintenance services and notes that such services do not include (and therefore, that prevailing wage and apprenticeship requirements do apply to) work that “improves a facility, adapts it for a different use, or restores functionality as a result of inoperability.” In other words, the NOPR holds that routine O&M services are likely not subject to prevailing wage and apprenticeship requirements – a detail that was not evident from the Initial Guidance.

The NOPR and Prevailing Wage requirements

The NOPR confirms the IRA is not a Davis-Bacon Related Act (“DBRA”), and therefore that compliance with prevailing wage requirements does not require DBRA certified payroll. Generally, the NOPR incorporates DBRA guidance regarding wage determinations and definitions (for example: laborer/mechanic, construction, alteration or repair, wages, employed) for purposes of prevailing wage compliance – but it excludes required contractual incorporation of DBRA provisions and certified payroll mechanisms.

Prevailing wage records pursuant to the IRA should not be submitted to the Department of Labor (“DOL”) for certification, and the DOL is not involved in enforcement mechanisms for noncompliance. The only consequence of noncompliance with prevailing wage requirements is loss of ability to claim IRA tax incentives.

Many developers and contractors were concerned about the uncertainty of regularly-updated prevailing wage determinations provided by the DOL (particularly in light of the August 23, 2023 final rule Updating the Davis-Bacon and Related Acts Regulations). The NOPR eased these concerns by clarifying that the applicable prevailing wage published when construction begins applies throughout the project, without the need to continue to update the wage if a new determination is published.

Wage determinations for individual projects, where SAM.gov published wages are not available, may be requested from the DOL pursuant to DBRA procedures (but, consistent with the Initial Guidance, also allowing email requests to IRAprevailingwage@dol.gov).

A wage determination, once issued, is binding on the project and can be “supplemental,” addressing selected labor classifications needed for a specific project and not already published. The NOPR confirmed the Initial Guidance’s direction to include specified information on any wage determination requests, and also expressly adopted Davis-Bacon Act review and appeal procedures for wage determination requests.

The NOPR and Apprenticeship requirements

The NOPR also provides additional clarity around the IRA’s labor hour, ratio, and participation requirements for registered apprentices. Of note, the apprenticeship ratio requirement, requiring that applicable apprentice-to-journeyworker ratios be satisfied, is a daily requirement. If the applicable apprentice-to-journeyworker ratio is not satisfied on any given day, the apprentice hours for that day do not count toward the labor hour requirement.

Additionally, if any registered apprentices in excess of the applicable ratio perform work on the facility, such apprentices must be paid the full prevailing wage rate for any hours worked. In contrast, the apprenticeship participation requirement is not a daily requirement. A contractor cannot spread out personnel schedules to avoid triggering the participation requirement. The participation requirement is designed to prevent taxpayers from satisfying the labor hours requirement by only hiring apprentices to perform one type of work – encouraging the use of apprentices across the full range of work performed with respect to the facility.

Similarly, the IRA’s good faith effort exemption is not a get-out-of-jail-free card. The good faith effort exemption allows taxpayers to satisfy the apprenticeship requirements by showing good faith efforts to obtain qualified apprentices from registered apprenticeship agencies, if the request is made in accordance with the usual and customary business practices of the registered apprenticeship agency and the request is denied or not responded to within five business days.

The NOPR, however, sets forth additional restrictions on use of the good faith effort exemption, noting that the apprentices should be requested from registered apprenticeship agencies with the necessary geographic scope, occupational training, and customary practice of placing apprentices with employers and also identifying the specific information that must be included on written requests for apprentices to registered apprenticeship programs. This requires the taxpayer to ascertain its workforce needs to determine how many qualified apprentices its needs to employ in order to satisfy the apprenticeship requirements; to identify applicable registered apprenticeship programs reasonably available to supply apprentices to the facility; and to demonstrate the capacity to employ apprentices in the requested occupations.

In addition, the NOPR provides that a one-time denial of a written request to a registered apprenticeship program does not automatically qualify the taxpayer for the good faith effort exemption. In the event of a complete denial of a written request, the taxpayer must also submit an additional request within 120 days of the previous request. Taxpayers may (and in all likelihood, will) need to submit a written request to more than one registered apprenticeship program in order to satisfy the good faith effort exemption.

The NOPR and overall compliance

In a boost to labor unions, the NOPR sets forth a new “Qualified Project Labor Agreement” (“Qualifying PLA”) concept, which provides that penalty payments for failure to meet prevailing wage and apprenticeship requirements will not apply if the facility is subject to a project labor agreement meeting certain requirements (provided that, any correction payments owed are paid on or before the tax return is filed).

A Qualifying PLA must, at a minimum: (a) bind all contractors and subcontractors on the construction project through the inclusion of appropriate specifications in all relevant solicitation provisions and contract documents, (b) contain guarantees against strikes, lockouts, and similar job disruptions, (c) set forth effective, prompt, and mutually binding procedures for resolving labor disputes arising during the term of the project labor agreement, (d) contain provisions to pay prevailing wages, (e) contain provisions for referring and using qualified apprentices consistent with the Initial Guidance, and (f) be a collective bargaining agreement with one or more labor organizations. In other words, a non-union or open-shop contractor cannot insulate itself from potential penalty payments using the Qualified PLA concept.

The NOPR, however, also helpfully provides practical flexibility prior to imposing penalties for “intentional disregard” of prevailing wage and apprenticeship requirements – significantly easing concerns of potential penalty obligations based on good faith mistakes and administrative burden. The IRA provides that failure to pay prevailing wages with intentional disregard results in a tripled correction payment and doubled penalty payment; and failure to comply with apprenticeship labor hours or participation requirements with intentional disregard results in a tenfold increase in penalty payments, from $50 per labor hour to $500 per labor hour.

Intentional disregard, according to the NOPR, must be “knowing or willful,” based on a determination “made by considering all facts and circumstances,” including whether the failure was part of a pattern of conduct or the absence of exercising reasonable diligence. From the prevailing wage perspective, the NOPR incorporates by reference mitigating factors mirroring DBRA requirements, which taxpayers will do well to heed as a protection against penalties. Those factors include posting prevailing wage rates at the facility site, incorporating prevailing wage provisions in project agreements, and undertaking quarterly or more frequent reviews of wages paid to ensure they are prevailing wages.

In addition, if a taxpayer submits a DOL wage determination request prior to work beginning, and the DOL wage determination is issued after work begins, penalties will not be imposed if the applicable correction payment is made to impacted individuals within thirty days of the DOL wage determination. In addition, correction payments to individuals may be made at any time in advance of the filing of a tax return claiming the increased credit (potentially limiting the amount of additional interest the taxpayer must pay at the elevated rates).

If a taxpayer makes correction payments before receiving a notice of examination with respect to the claim for the increased credit, the NOPR provides a rebuttable presumption against a finding of intentional disregard. In other words, the NOPR broadcasts the intent to incentivize taxpayers to promptly self-correct errors in compliance with prevailing wage and apprenticeship requirements, waiving the penalty payments for such correction and minor discrepancies.

In conclusion, the NOPR provides helpful additional instruction to parties seeking to ensure compliance with prevailing wage and apprenticeship requirements pursuant to the IRA. As the renewable energy industry adapts to this new normal, the NOPR outlines a more pragmatic path to compliance than many in the industry had feared based on Treasury’s Initial Guidance. Some questions remain unanswered (including the timing of DOL responses to wage determination requests and the lack of standard reporting forms), but the NOPR allows parties to begin negotiating appropriate provisions in project agreements with more certainty on the compliance standards necessary to satisfy prevailing wage and apprenticeship requirements.

Monica Dozier and Amy Puckett are attorneys at Bradley Arant Boult Cummings LLP who regularly advise clients on labor and employment issues in the renewable energy industry.

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In a new weekly update for pv magazine, Solcast, a DNV company, predicts that El Niño will likely bring lower than normal solar power production through winter in the United States. Its analysis is based on data collected from previous El Niño events.

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Reducing the cost of solar electricity will be the key to unlocking the next chapter of the energy transition: a green hydrogen economy, according to Jim Tyler, CEO of solar technology company Erthos,.

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Form Energy released a white paper that provides further evidence that multi-day energy storage, like its iron-air technology, can substantially reduce the costs for New York to achieve its ambitious decarbonization targets.

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Transmission competition is the key to upgrading our electricity grid in a cost-effective manner. FERC must embrace competition and deliver on its mandate to ensure just and reasonable rates for consumers.

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In a new weekly update for pv magazine, Solcast, a DNV company, presents the solar irradiance data it collected for North America this month. July’s high pressure in the southwest and trough in the northeast dramatically influenced the region’s solar energy production.

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To reach the 6 TWh of energy storage needed to clean the grid by 2050, we need to grow grid-scale energy storage by 98.4 times. Panelists in a recent Reuters webinar said that the path requires facing critical challenges as well as continued technology innovation, public-private partnerships, regulatory reforms, and more.

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The central tension at the heart of the IRA – limiting dependence on competitors like China while undergoing an energy transition that we cannot accomplish without them – will inform, and even dictate, so much of U.S. policy going forward.

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Leveraging the geotechnical consultant as a member of the development team leads to a more holistic approach to the design and construction of the solar project and allows them to provide valuable cost-saving advice and recommendations.

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Failure to reimburse employees for charging EV fleet vehicles at home can have serious consequences. Employers can reduce that risk by offering employees an IRS-compliant program that accurately reimburses employees.

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This year, DOE recognized five organizations that exemplify the benefits that community solar can bring with $10,000 grand prizes, and recently launched a new round of the Sunny Awards.

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Small-scale PV systems drove the installation of more than 200 GW of solar capacity last year and could support more than 300 GW this year. That means a reset for utilities.

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Passing these bills would make the state among the most ambitious in the Midwest when it comes to growing storage capacity and encouraging business models that unlock the full potential of this technology, like the “virtual power plant” model.

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Strategies and best practices for building trust and overcoming opposition to solar project development, based on a Clean Power Hour podcast that delved into public acceptance challenges around solar projects.

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In a perfect world, trackers in solar installations track the sun and perfectly minimize row to row shading; however, this is not always the case, as described in examples in which trackers deviate from the idealized tracking angles, go offline and stow down due to high wind speeds.

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To realize the IRA’s full potential, the solar industry needs well-defined and prompt guidance regarding the IRA’s implementation. Additionally, federal permitting reform is needed to address issues of congestion, interconnection and transmission.

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A well-balanced project design is one that maximizes use of the buildable space for a parcel of land while avoiding costly impacts from flood damage during the operational period.

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Deploying local solar technologies like rooftop and community solar in conjunction with battery storage unlocks a stronger, more flexible electric grid and also creates the lowest-cost pathway to a 100% clean energy future.

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The funds flowing from the U.S. Inflation Reduction Act (IRA) could prompt solar installers to diversify their offerings to homeowners. The IRA may also lead to consolidation among solar equipment manufacturers, writes Jessica Fishman, a clean energy marketing professional.

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While hydrogen is poised for growth, it is not poised to knock off—or even compete with—solar and wind. Instead, if done correctly, hydrogen might help drive further adoption of wind and solar.

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The Paris Agreement of 2015 marked a milestone in the effort to combat climate change, and since then, governments including Canada and the United States have undergone a political and economic transformation focused on achieving net-zero goals, with renewable energy resources, particularly solar energy, playing a vital role.

Solar energy has become a significant player in the race to reduce greenhouse gas (GHG) emissions due to several factors. The cost of solar panels has plummeted in recent years, making them more accessible and affordable. Technological advancements have also made solar systems more efficient and reliable, enhancing their appeal as a sustainable energy solution.

Canada and the United States have committed to achieving net-zero emissions by 2050. President Biden has set an ambitious target of achieving 100% clean electricity in the U.S. by 2035. To attain this goal, the Biden administration has proposed various measures, including tax incentives, investments in renewable energy infrastructure, and the promotion of community solar projects.

Many companies have stepped up to take advantage of these incentives and to help businesses and organizations achieve net-zero emissions. One key advantage for these companies is the availability of financial incentives for solar and renewable energy projects. In the U.S., federal tax incentives exist for residential and commercial solar installations. The most significant incentive is the solar investment tax credit (ITC), which provides a credit of 30% of the installation cost for solar projects in residential and commercial properties. State-level tax credits are also available in many states. New York is particularly attractive for solar developers due to its state tax credit of up to $5,000 for commercial solar installations.

The shift toward net-zero also presents opportunities through community solar projects. These initiatives enable multiple households or businesses to benefit from a single solar project, allowing individuals with space or resource constraints to access solar energy. Community solar projects can also extend the benefits of solar power to low-income households and communities that may otherwise struggle to access renewable energy, leading to long-term cost savings.

Renewable energy credits (RECs) are another avenue for supporting the shift towards net-zero. RECs provide businesses and organizations with a means to support renewable energy projects without directly purchasing the generated electricity. Whenever a renewable energy project produces electricity, it generates RECs, which can be sold to entities seeking to offset their carbon emissions. This creates an additional revenue stream for renewable energy projects, facilitating their continued growth and expansion.

The political momentum toward achieving net-zero targets has profoundly impacted the solar energy market, positioning it as a central player in the transition to a low-carbon economy. Canada and the U.S., in particular, have demonstrated their commitment to these targets through various measures, including tax incentives, community solar projects, and the utilization of RECs. Notably, the responsibility for electricity falls under the jurisdiction of states and provinces in both countries. This means that the demand, supply, and formulation of electricity-related policies and regulations primarily originate at the state and provincial levels. While federal-level incentives, such as the ITC, exist in both countries, reducing federal income tax liabilities for solar system installations, there are also state and provincial incentives specific to each region.

New York sets an example

In the U.S., for example, the New York State Energy Research and Development Authority (NYSERDA) offers financial incentives for installing renewable energy systems in non-residential, large commercial, industrial, and single-family residential projects within the state. These incentives aim to promote the adoption of renewable energy technologies, including solar.

Similarly, Canada has introduced its own initiatives to support clean technology projects, including solar. Under the Inflation Reduction Act, the Canadian government has unveiled a 30% investment tax credit for investments in clean technology projects. This tax credit serves as an incentive to stimulate investments in solar and other clean energy projects.

From a policy perspective, solar projects are generally welcomed at the federal level and in select states and provinces. For example, a solar developer can access the NYSERDA grant in upstate New York once the project has obtained full permits and the grid interconnection fees have been paid.

While awaiting further details on the implementation of the IRA, solar companies can generally access funding opportunities at the federal and state levels. The availability of funding for renewable energy projects is relatively straightforward, providing a favorable environment for the growth and expansion of the solar industry.

As an avid traveler, I often engage in discussions about the visible impacts of global warming and the urgent need for action. Among the most frequently mentioned concerns are rising sea levels, intensified hurricanes, devastating floods, and the alarming retreat of glaciers. I had a profound encounter with the effects of climate change when I flew over Greenland in October 2022. Witnessing vast stretches of exposed rocky terrain that were once blanketed with ice and snow was a stark reminder that the ice continues to melt at an alarming rate. These firsthand experiences serve as undeniable evidence that climate change is a tangible reality.

Beyond my personal observations, there are numerous other examples of the visible effects of climate change that people can witness around the world. One prominent illustration is the increased frequency and intensity of wildfires. In regions such as California, Australia, and the Amazon rainforest, devastating wildfires have become more prevalent, destroying vast areas of land, displacing communities, and releasing significant amounts of carbon dioxide into the atmosphere, further exacerbating climate change.

Another visible consequence of climate change is the bleaching and deterioration of coral reefs. These vibrant and biodiverse ecosystems, found in tropical and subtropical waters, are subjected to warmer ocean temperatures and acidification due to higher atmospheric carbon dioxide levels. As a result, coral reefs are experiencing widespread bleaching, leading to their decline and the loss of critical habitats for marine life.

Furthermore, changing weather patterns, including more frequent and severe heatwaves, droughts, and extreme precipitation events, are evident in many parts of the world. These extreme weather phenomena disrupt ecosystems, harm agriculture, and food production, and pose significant risks to human health and well-being.

It is crucial to recognize that while the effects of climate change are already visible, there is still hope for meaningful action. By collectively embracing sustainable practices, transitioning to renewable energy sources, implementing effective policies, and promoting conservation efforts, we can mitigate the impacts of climate change and work towards a more sustainable and resilient future for our planet.

Dr. Richard Lu Dr. Richard Lu is president and CEO of SolarBank. He has over 25 years of global energy experience developing and implementing growth strategies for organizations in North America, Europe, and Asia.

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We need a domestic content standard that would draw distinctions between panels made entirely here and those with imported components.

Last month, as Vice President Harris toured an expanding solar factory in Georgia, she noted the vital connection between domestic manufacturing and deployment in the fight against climate change, saying “When we invest in climate, clean energy, and U.S.-based manufacturing, we invest in America and her people.” She was right to recognize that as we work to reduce our greenhouse gas emissions, we must simultaneously invest in our independence from foreign adversaries and create good-paying American jobs. Unfortunately, I believe last week’s domestic content bonus credit guidance issued by the U.S. Treasury Department may have lost sight of this critical goal.

For decades we have tried to break our unhealthy dependence on fossil fuels, whose global price is controlled by authoritarian regimes and whose profits fund aggression, most recently the Russian invasion in Ukraine. Again and again, we have seen this dependence on fragile supply chains result in economic destruction, price gouging of consumers, and job losses. But, as Vice President Harris alluded to, the rapidly expanding solar industry represents a way out of this destructive cycle while providing people with fulfilling careers.

To that end, for the first time a coalition of solar manufacturing companies have gotten together to try to break through the barriers in the way of a robust domestic supply chain: the Solar Energy Manufacturers for America (SEMA) Coalition. Our mission is to bring home the manufacturing of the entire panel – from cell to wafer to ingot to polysilicon – so that we are able to produce the cheapest form of new electricity here at home.

Our coalition worked together with champions in Congress such as Senator Jon Ossoff, Representative Dan Kildee, and Chairman Ron Wyden, to include a new tax incentive in the Inflation Reduction Act (IRA), Section 45X . Also known as the advanced manufacturing production tax credit, this provision was designed to provide the certainty necessary to invest billions of dollars in new factories needed for a domestic solar supply chain. This would allow us to finally return to the solar manufacturing game and compete with countries such as China that have built up such a tremendous lead.

To ensure sustained scale and success, the domestic content bonus was intended by the Congress to supercharge 45X, providing the necessary demand certainty for those factories to remain open and ensure true American clean energy independence. But for this effort to succeed, we need a domestic content standard that would draw distinctions between panels made entirely here and those with imported components.

As it relates to the guidance recently issued from the U.S. Treasury, a few basic principles about the solar supply chain must be understood.

1. Solar development is very competitive. If your competitor gets a bonus to the tune of tens of millions of dollars and you can’t, you won’t build the project. This means the “bonus” standard becomes a de facto standard for most U.S. solar development.
2. Our competitors already have billions of dollars of infrastructure in place to manufacture each step of the supply chain, which they have subsidized for decades. But we’re just getting started. While the 45X credit can get a factory built and operating for the duration of the IRA, if any one step of the supply chain is not recognized in the domestic content standard, there is no sustained, long-term advantage to building it here, as you can simply import pieces and get the same “bonus.” This is even more acutely true for the wafer and polysilicon facilities, since they are the most expensive to build.
3. The more these expensive factories are built overseas (whether in China, India, Malaysia, or somewhere else) the harder it becomes to justify spending billions to build a competing plant here in the future.

China produces 97% of the world’s solar wafers – giving them substantial control over not only this critical piece of the supply chain, but the polysilicon that goes into producing the wafer. While the bonus released last week was designed to unlock future cell production in the U.S., a number of core components of the solar value chain were excluded. This will result in continued reliance on Chinese imports, many made without the robust labor and environmental standards we have in the United States.

The simple fact is the guidance issued last week will probably result in the scaling back of planned investments in the core, strategic components of the solar value chain. This likely will, unfortunately, cement China’s dominance over the solar industry and put us right back where we are with oil and gas – a price taker in the global marketplace, dependent on someone else to meet our energy needs.

The Administration must take a holistic view of the IRA when implementing the domestic content bonus so that it supercharges 45X and supports Congress’ key policy goal of reshoring the solar value chain. As long as the U.S. does not have an end-to-end solar manufacturing supply chain of all the strategic components of a solar panel, there is more work to be done. The SEMA Coalition remains committed to work with the Administration and Congress to implement policies that can finish the job of fully reshoring the manufacturing of the solar supply chain and creating good-paying American jobs while strengthening our energy and national security.

Mike Carr is the executive director of the Solar Energy Manufacturing for America (SEMA) Coalition. He previously served as the principal deputy assistant secretary for the Office of Energy Efficiency and Renewable Energy and the senior advisor to the director of energy policy and systems analysis at the U.S. Department of Energy from 2012 to 2015.

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Exploring California's energy transition with the help of alternative battery technologies.

California has recently introduced a new net metering policy known as NEM 3.0. This policy is designed to help the state achieve its 2045 goal of a 100% clean energy grid by encouraging the installation of solar panels and energy storage systems in homes and businesses. One of the key features of NEM 3.0 is the inclusion of batteries in the net metering program, which means that homeowners can now store excess solar energy during the day and use it at night when the sun is no longer shining.

This is a significant development, as it allows for the creation of virtual power plants (VPPs). A VPP is a network of decentralized energy sources, such as solar panels and batteries, which are connected and managed through a central control system. There are several types of VPPs, including those owned and operated by utilities and those owned and operated by third-party aggregators.

VPPs in use and the benefits

The U.S. Inflation Reduction Act, which includes incentives for electric vehicles (EVs), solar panels, and home batteries, has energy experts anticipating that VPPs will see significant growth in the United States soon. An example already in operation is the Tesla VPP in California. Currently operating in select communities, this particular VPP aggregates residential solar panels and battery storage systems to form a distributed energy resource (DER) network that can provide grid services such as frequency regulation and capacity.

Working with local utility Pacific Gas and Electric, Tesla launched another new program that pays eligible Powerwall owners to provide extra electricity to the grid when it’s vulnerable to blackouts. The Tesla VPP is one of several networks developed by technology companies and is expected to play a vital role in California’s transition to a more flexible and renewable energy grid.

The benefits of using VPPs as part of a clean energy grid include:

• Reducing the need for new infrastructure, as they can provide a more adaptable and resilient source of electricity
• Lessening greenhouse gas emissions by integrating renewable energy sources into the grid
• Providing a more stable and reliable source of electricity, delivering backup power in the event of an outage

Leaving lithium-ion batteries behind

Despite the many advantages of VPPs, placing battery systems into millions of homes could have unintended consequences. While lithium-ion batteries are used in most current energy storage systems, they come with high costs and safety concerns. If they get too hot or experience an internal short, lithium-ion batteries can begin a process called thermal runaway. The batteries can vent toxic gases such as hydrogen fluoride and even catch fire. These fires can be difficult to extinguish and are a growing cause of structure fires in cities such as New York and Mumbai.

Hundreds of thousands of home storage systems will have to be installed for VPPs to make a meaningful contribution to tomorrow’s grid. Still, the fear of fires could stop any momentum before it has a chance to build.

A clean grid future

Scientists and startups worldwide are creating new battery technologies that are safer and more reliable than traditional lithium-ion batteries. Several innovators are working hard on lower-cost, non-lithium battery options for utility-scale, long-duration storage, keeping non-flammable and non-toxic solutions at the forefront.

Implementing NEM 3.0 and including batteries in the net metering program represent a significant step toward achieving California’s clean energy grid goal. Creating VPPs using decentralized energy sources will revolutionize how society produces and consumes energy. But finding alternative battery technologies with fewer risks and at a lower cost than lithium-ion is imperative, and the success or failure of VPPs will likely depend on convincing homeowners and businesses that there are alternatives.

Mukesh Chatter Image: Alsym Energy, Inc.

Mukesh Chatter is the president, CEO and co-founder of Alsym Energy, a battery technology company developing high-performance, low-cost batteries to enable a zero-carbon electrified future for all. He is a successful serial entrepreneur with a track record of developing advanced technology products and leading startups from launch to success. Mukesh co-founded Nexabit Networks, a terabit switch/router company, and led the company as CEO until its acquisition by Lucent Technologies. After the acquisition, Mukesh served as the vice president and general manager of IP Products at Lucent. Mukesh also co-managed NeoNet Capital LLC, an investment firm focused on funding out-of-the-box, innovative ideas.

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Supply chain, tariffs, workforce, permitting and interconnection, and energy equity issues surround the rapid buildout of solar energy in the U.S.

Solar adoption has made important strides in the last decade, and the Inflation Reduction Act (IRA) has great potential to help those adoption rates skyrocket. According to SEIA projections, solar capacity is projected to increase to 69% more than what would have been expected without the IRA. Furthermore, it estimates that by 2032, the U.S. will have installed 682 total gigawatts (GW) — more than five times the amount installed today.

That’s due, in part, to the never-before-seen incentives and provisions in the IRA to drive solar adoption and combat climate change. The IRA includes a tax credit of 30% that applies to solar and energy storage projects, and that credit can increase by 10%-20% depending on where materials are manufactured or where the project is located.

Despite its promise, the pathways to IRA benefits are convoluted. Currently, solar tax credits only last until 2032, and there are numerous challenges along the way that the industry, and federal and state governments must overcome. Let’s dive into the current challenges and how the industry can overcome them.

Solar supply chain

Currently, 80% of the panels consumed by the U.S. solar industry originate in four Southeast Asian countries, namely Cambodia, Malaysia, Thailand, and Vietnam. Last June, the federal government issued a 24-month reprieve on tariffs for panel imports from these four countries in response to the Auxin petition to the Commerce Department that investigated whether solar companies were circumventing tariffs by shifting their operations to these countries. Moreover, the U.S. government is also navigating the allegations of human rights abuses in manufacturing and trade concerns with China. All of this is directing the U.S. solar industry to secure a domestic supply chain.

We have started to see the results of these efforts. Nearly $5 billion in solar manufacturing investments, including 47 new manufacturing plants have been announced since President Biden took office. Additionally, the IRA includes two specific tax credits to bring solar manufacturing back to the United States. While these are positive steps towards a domestic supply chain, establishing manufacturing capabilities that can meet industry needs isn’t going to happen overnight. It will take years for manufacturing output to match the solar panel demand of the U.S. solar industry. The 24-month reprieve is essential for the industry to get its bearings as it strengthens its local manufacturing base.

Unfortunately, a controversial Congressional Review Act (CRA) seeks to roll back the current freeze on tariffs. Through a joint letter, clean energy trade groups are currently urging members of Congress to oppose the bill and its potentially devastating effects on the industry. As of most recently, the House Ways and Means Committee voted 26-13 to send the solar CRA to the full House. If passed, the CRA would compromise the economics of current and future projects by making some too expensive to deploy, potentially eliminating 14% of the solar industry’s anticipated deployment in 2023, and costing 30,000 jobs in the solar industry. This would negate the intentions of the IRA and elongate our clean energy transition timeline. A well-oiled supply chain requires strong commitments from developers to procure local materials. While that support and commitment is there, any setbacks such as through the CRA can completely derail the vision that the solar and clean energy industry has for the future.

Workforce shortages

IRA’s build-out of a domestic supply chain as well as clean energy asset deployment will not happen without an adequate number of skilled workers. SEIA projects an additional 200,000 solar jobs will be created by the IRA, leading to 538,000 in total by 2032. Even when domestic manufacturing processes are solidified, there will still be a worker shortage to fully realize the IRA’s potential.

Government, industry, labor, community, and workforce training leaders must convene to guide the creation of industry relevant training programs. In addition, local governments must provide adequate financial compensation especially to retain solar trainees who opt to leave positions in other industries, and developers can offer assurances in regard to hiring once training is completed. States also need to implement relevant skilled training at high school and community colleges to encourage workers to get into solar and clean energy manufacturing. States that offer robust solar tax incentive in addition to skilled training programs will rise to the top in attracting clean energy investment.

Permitting and interconnection woes

Permitting, interconnection, and transmission remain the biggest challenges yet to be solved. Lack of transmission development remains the number one hurdle for scaling clean energy assets as well as number one cause of interconnection delays for distributed generation. The Federal Energy Regulatory Commission reports that about 1,700 GW of solar, wind, and storage await interconnection — up 28% from last year.

Solar industry groups are proactively working to streamline permitting processes for solar installation, but permitting reform will mainly rely on the speedy deployment of transmission infrastructure that would enable large volumes of solar and wind projects to come online. The sooner we can move on adding new transmission capacity, the quicker we can meet the renewable energy capacity demand that will follow the roll-out of IRA incentives. Even with IRA’s allocation of funding towards transmission and grid upgrades, differences between states’ approaches to transmission development can derail infrastructure projects. With this, both state and federal decision-makers will need to work closely with developers and renewable energy industry groups to strategically deploy new transmission and expedite interconnection processes.

Energy equity

Lastly, it would be amiss to not touch on energy equity. A top priority under the IRA is ensuring low-income and energy communities benefit from the multitude of benefits ranging from job and wealth opportunities to clean energy access. For the past decade, solar incentives have largely defaulted toward development in greenfields and around higher income communities. Now with the IRA, a 10% bonus tax credit is available for projects in “energy communities,” defined as brownfields, former coal mines, and coal-fired power plants. Another 10%-20% tax credit will be allocated to projects on Indian land or in low-income communities. The Greenhouse Gas Reduction Fund, a key funding source within the IRA, also offers $7 billion to states and local governments for projects and initiatives that support greenhouse gas reductions, with an emphasis on projects for low-income and disadvantaged communities.

Incentives for both energy communities and low-income communities will increase energy equity, but they both come with their challenges. For energy communities, the biggest barrier right now is lack of comprehensive mapping tools to help identify those sites, and with brownfields especially, there are liability risks and lack of clear understanding on who would assume those risks.

One of the key ways for developers to ensure energy equity is through community solar, something the federal government hopes to see 700% growth in by 2025. The IRA allocates a 20% bonus incentive for projects on low-income housing or designated low-income economic benefit projects. Development of community solar projects in urban areas, brownfields, energy communities, and low-income communities will ensure that the benefits flow easily to low-income residents.

Despite the federal incentives, developers cannot utilize these incentives unless states have an enabling legislation to deploy community solar projects. California’s Public Utilities Commission is currently deliberating whether to create a community solar program that ensures at least 51% of subscribers are low-income, and New York is incentivizing community solar projects on brownfields.

But incentives aren’t one size fits all; different communities have varying needs and states must be mindful of what incentives they currently offer and how that merge with the IRA incentives. States should invite the perspective of qualified solar and storage industry participants to better understand how different permutations of incentive structures will affect projects and establish an incentive package that accommodates the unique income structures, energy rates, and environmental obstacles for that region.

Other barriers that developers are currently faced with are zoning constraints and solar development moratoriums in suburban and rural areas, all of which are red flags for industry.

The IRA presents plenty of viable paths for communities and businesses across the country to utilize renewable energy. It’s a historic moment for the solar industry, but right now, developers and other market participants face far too many uncertainties and potential roadblocks to quickly benefit from the landmark legislation. The solar industry must continue to collaborate with multiple parties to improve the supply chain and development processes to expeditiously reap the benefits the federal government is offering and meet the vision this legislation was set out to achieve.

Pari Kasotia is senior director and head of policy at DSD Renewables.

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Maryland’s new community solar program provides a blueprint that other states can follow, helping to increase use of locally generated energy and offering numerous benefits to communities.

Maryland has a history of supporting solar and has set an ambitious goal of 100% renewable energy generation by 2035. Now the state is on track to expand a burgeoning solar market segment, community solar. Maryland’s new community solar bill provides an excellent opportunity to accelerate the state’s shift to renewable energy. Building on its 2015 Community Solar Pilot Program, House Bill 908 makes much-needed improvements to that program and makes the program permanent. This bill will allow Maryland to join the ranks of the 22 other states that have implemented community solar programs, offering access to solar power for both residents and businesses statewide.

The pilot program proved effective in kick-starting community solar initiatives in Maryland, and it is anticipated that it will provide energy to approximately 90,000 customers in the state before its expiration at the end of this year. The pilot also provided a valuable learning opportunity that has informed development of the new program.

Based on lessons learned during the pilot as well best practices employed by programs across the United States, the permanent program incorporates several upgrades that are formulated to revitalize Maryland’s community solar market. To avoid delays in permitting and getting projects built, the program calls for greater coordination between the Public Service Commission (PSC), utilities and the authorities having jurisdiction (AHJ) responsible for project queues. The program is expected to be more inclusive and less limiting than the pilot, ensuring that solar access is more equitable. Furthermore, establishing a permanent program will provide the essential policy certainty required for any solar initiative to thrive.

The new program will allow for broader participation by all customers, including low- to moderate-income (LMI) households. It will require community solar projects to dedicate 40% of their solar generation to LMI subscribers. To make this goal more achievable, the program allows LMI customers to provide self-attestation of their LMI status, making it easier for them to sign up for community solar projects. The program also introduces consolidated billing, simplifying participation in the program and lowering the entry barrier by allowing customers to get just one electricity bill.

In addition to helping customers, consolidated billing and self-attestation for LMI will simplify the process for owners of community solar gardens to gain subscribers.

The program also makes significant improvements in project requirements. There is now additional system size capacity allowed on rooftops, parking canopies, parking structures, industrial areas, brownfield sites and on or over transportation or public rights of way. Also included are clean fill sites — land previously zoned for industrial use or was ecologically compromised, provided the site is not targeted for mitigation or restoration. Agrivoltaics projects, which combine farming with solar panels, will now be authorized to utilize co-location on farms, facilitating greater economies of scale for developers.

The new program will also eliminate the restrictive programmatic structure within the pilot and remove project categories, project-generating capacity limits, yearly programmatic and utility-specific capacity limits and sunset dates. Whereas the pilot had an overall cap of 580 MW, the new program’s total capacity is subject only to the state’s overall net metering capacity limit, allowing developers like Standard Solar to bolster community solar development within Maryland.

The bill is particularly significant for Standard Solar, as our company’s presence continues to expand in our home state of Maryland, contributing to delivering affordable, reliable, clean energy to Marylanders.

But the bill’s significance could — and should — go beyond Maryland. Community solar is an important market segment because it increases access to solar with locally generated energy, offering numerous benefits to communities. Combining the best elements of successful programs around the country, Maryland’s new community solar program provides a blueprint that other states can follow. As more states see the value of community solar and enact their own programs, having an example of a robust program will make them more likely to succeed in supporting this crucial market.

Given the pressing need to move away from fossil fuels and the numerous incentives for clean energy provided by the Inflation Reduction Act, there is no better time than now for all states to establish programs like Maryland’s.

Trevor Laughlin Trevor Laughlin is policy and regulatory affairs analyst with Standard Solar.

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Three tips to help optimize commercial solar installations.

Module level power electronics (MLPE) are becoming increasingly popular in commercial rooftop and ground mount solar installations due to their ability to improve return on investment (ROI) through a combination of factors: increased energy production, greater design flexibility, and lower O&M costs. The following are three common questions asked by installers when designing or installing power optimizer MLPE systems for commercial projects.

What is the best power optimizer-to-module ratio for my project?

When designing a MLPE system, it is important to determine the level of optimization required for each project. This should be based on several factors: available roof space, level of shading, and cost.

The two most popular configurations are:

• 1:1 ratio – In this configuration, one power optimizer is attached to each module. This ratio is commonly favoured for residential installations due to space limitations and other challenges that can limit energy production, e.g., the roof has different pitches or orientations, or there is shading from nearby trees. In this scenario, a high level of optimization is required to squeeze every watt of energy from the array.
• 2:1 ratio – As installation size increases, equipment cost becomes a more important factor. Typically, commercial installations have large, flat roofs and fewer obstructions that can cause shading. In this scenario, a 2:1 ratio (two modules to one power optimizer) is generally favoured, as it provides sufficient optimization and increased energy production, while also reducing BoS components and operational costs.

Oversizing DC/AC ratio: how much is too much?

It is a fact of life that PV modules do not consistently perform at their nominal output rating. Module output power is affected by the weather, the sun’s position during the day/different seasons, local site conditions, and array orientation. In addition, module output power may decrease due to aging, soiling and shade. Using MLPE in your project maximizes power production in all scenarios, and can improve system ROI.

Oversizing the array (in comparison to the inverter’s AC power) also helps to increase energy production. This trend became popular when PV module price levels started to fall. Producing more DC power than the inverter can turn into AC energy means the system will produce peak power for longer on sunny days, and it increases the probability that it will produce maximum power in low-light conditions.

However, too much oversizing may negatively affect plant production, resulting in a longer payback period. This is because inverters are designed to generate output power up to a maximum AC power that cannot be exceeded, and they limit (clip) the power when the actual produced DC power is higher than the inverter can output. Added to this, as oversizing causes the inverter to operate at high power for longer periods, it can also reduce the inverter’s lifetime if its oversizing capacity is not sufficient.

Inverter oversizing capacity can range considerably from 135% to 200%, depending on the brand or model of the inverter. Therefore, it is essential to check the manufacturer’s information to ensure you keep oversizing within recommended limits.

How can I avoid PV connector issues?

PV connectors are a crucial component of any solar system. However, if not installed properly during installation, there may be future consequences. Below are three common connector-related errors that can occur during installation. The good news is these can be easily avoided with a little know-how.

• Failing to properly close connectors – When installing connectors, it is important to make sure they are seated properly, as failure to do so can cause arc faults. When making a connection, ensure there is an audible click, and give both connectors a firm tug. This will let you know the connectors are securely fastened.
• Using different brands of connectors in the same install – Many module manufacturers produce their own connectors. However, this can lead to situations where installers inter-mate different brands of connectors, not realizing this is not NEC-code compliant. While different connectors may fit together initially, over time they might not work well together. One connector could corrode, or there may be a mechanical mismatch that no one sees, and so it heats up, potentially causing a problem that could become an arc fault in the future. The best way to safeguard against this is to ensure that only one brand of connector is used in each installation. If this is not possible, make sure all of connectors used are UL listed to ensure compatibility.
• Improper Crimping – When installing connectors, be sure to follow the manufacturer’s instructions that specify allowable wire types and strand counts, as well as the crimping tools required to maintain the integrity of the crimped connection.

Kleber Facchini Kleber Facchini has more than 15 years’ experience in electrical engineering, applications and product management in the renewables and utility equipment industry. As director of technical marketing, commercial & utility for SolarEdge North America, he is responsible for conceiving, defining, and launching all related products across the continent. He also oversees the applications engineering team, which works directly with SolarEdge’s installer partners.

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Electric vehicles can help buffer the grid but policies and regulations are needed along with compensation mechanisms, and the use of software to modulate EV charging to meet the needs of the grid in real time.

The impact of electric vehicles (EVs) on the world’s power grids is a top concern for utilities because each EV represents a load on the system equivalent to a single home. In the future, if everyone drives home after work and then plugs in their EV as the sun is setting and when rooftop solar production drops, our already stressed grid networks might face regular power outages and the costs of maintaining grid reliability could mushroom.

Yet a tipping point for EVs in becoming mainstream consumer offerings is steadily approaching. By 2030, government vehicle fuel efficiency regulations and continued development of advanced battery chemistries and manufacturing capacity are likely to make EVs cheaper to purchase than competing liquid or gaseous fuel-powered vehicles. Consumer Reports noted that the total cost of ownership of an EV is cheaper than a traditional gasoline-fueled vehicle. So, the future will soon be today.

For the electric power sector, EVs are a boon because they increase demand for kilowatt hours. While basic load growth is good for the sector, the uneven distribution of that growth within a specific location or at a specific time of day could prove burdensome for utilities. Actively managing and spreading the EV charging load across infrastructure assets may not only prevent infrastructure upgrade costs but may also decrease grid balancing costs.

Solar and EV parallels

Concerns over EVs echo the industry’s past views of solar energy. As rooftop solar systems began to pop up at random across the grid, they had the potential to impact utility resource planning. As costs continued to come down, market traction multiplied. Also, the widespread adoption of solar transformed assumptions about grid management, with excess solar production during the middle of the day, when demand was low, and declines in solar production in the early evening, when demand ramped up.

Then there’s the equity issue. Only some consumers can afford solar or EVs, and others feel shut out. The issue of access permeates the new energy landscape, where prosumers are purported to be in the driver’s seat, contributing to climate change solutions by generating and consuming electricity in the most sustainable manner possible, right in their own homes. As with other forms of new technology, early adopters lean toward more affluent single-family homeowners. Yet to meet the scale of the energy transition, high-end prosumers can’t do the job alone. They need help from the rest of society. New energy-as-a-service business models and government incentives, such as those included in the Inflation Reduction Act, are allowing more consumers to participate in the new energy economy by lowering costs for solar, batteries and EVs.

Bidirectional utility

Like solar, EVs can be good grid neighbors if public policies and regulations are put in place to allow these resources to be bidirectional. With solar, it was the policy of net metering, which essentially allowed solar asset owners to barter for electricity with host distribution utilities, sending clean electricity back to the grid when there was no demand for it on site. With EVs, a similar relationship is possible, if regulators figure out an adequate compensation mechanism for EVs to buffer the grid with the “batteries on wheels” and the ability of software to modulate EV charging to meet the needs of the grid in real-time.

The technology for EVs to be a viable grid asset is already here. Vehicle grid integration (VGI) technologies, including software, enable EVs to participate in grid balancing. EVs can do this by modulating the rate of power at which the battery is charged, or by also providing power back to the grid, known as vehicle-to-grid (V2G). Though this may seem like a win-win for the electric power sector, V2G is still a fledgling solution with significant hurdles to overcome. Opportunities for deployment vary significantly by location depending on the confluence of a growing EV population, an intelligent grid, penetration of renewable resources, and open market regulatory structures.

EV opportunities and challengesThe opportunities for EVs to be viable grid assets are clear:

• Batteries in EVs can potentially respond more quickly and accurately to grid signals than other utility grid service assets, such as natural gas-powered peaker plants.
• When charged up with on-site solar systems, EV batteries are cleaner than natural gas peaker plants.
• The potential EV resource is huge. In California alone, one estimate by the Climate Center, projects that 100 GW of EV capacity will be available if the state’s EVs were all bidirectional.

The outstanding challenges that remain include:

• The vast majority of EVs being sold today are not bidirectional. The Nissan Leaf is one of the few models that include this feature.
• Today’s market offers very few bidirectional charger/EVSEs capable of enabling V2G. The speed and accuracy of EVs in responding could boost grid efficiency, but in most markets, these performance advantages are not compensated accordingly.
• Many wholesale markets are just starting to figure out how to accommodate EV charging into portfolios of DER assets being integrated into virtual power plant aggregations. Given that, the business case for EVs as grid assets is confusing because EVs are road-facing assets first and grid assets second.
• Utility interconnection agreements and site analyses for V2G are lengthy processes. EVs as a solution

Thanks for advances in artificial intelligence and software platforms, EVs can represent solutions to the variability of weather (and the corresponding availability of renewable energy resources) by modulating charging when there is a surplus of clean energy available. When there’s a shortage of supply, EV charging can be throttled back. Because solar is available during the day (and the wind often blows strongest in the early evenings and night), possible synergies emerge. Our energy systems are being transformed by dramatic increases in distributed energy resources (DERs) such as solar and EVs. These DERs are challenging conventional thinking. EVs could be the most transformational of all with smart software serving as the key enabling technology to maximize value for both asset owner and grid.

Varun Deshpande is a product panager for the predictive controls & forecasting team at AutoGrid Systems (a Schneider Electric company). He has been working in the energy industry for over 7 years and has extensive experience in areas of renewable energy integration, battery & DER management & AI in Energy. He is passionate about utilizing information technology & data science to add value to the energy grid. Varun is a graduate of Carnegie Mellon University with a degree in Energy Science Technology & Policy.

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The challenges with proposed permit conditions are likely to get worse, but drawing on the lessons of the past can help new project proponents navigate the pitfalls and emerge from the permitting process positioned for success.

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Now that energy storage technologies are elibible for the investment tax credit, the central storage question is no longer whether to deploy it, but how much and how fast.

The Inflation Reduction Act of 2022, signed into law in August, is bringing about significant changes to energy investment in America.

Annual installations of solar in the United States are expected to consistently reach 30 to 40 GW (DC) by 2024, according to the U.S. Solar market Insight Q4 2022 report, released by the Solar Energy Industries Association and Wood Mackenzie. The report forecasts average annual growth of 21% from 2023 to 2027, across all solar segments, New forecasts from BloombergNEF anticipate that the IRA will drive about 30 GW/111 GWh of energy storage in the U.S. between 2022 and 2030.

In addition to extending the investment tax credit (ITC) for solar and other renewable energy technologies for at least 10 years, the IRA also includes an expansion: For the first time, most energy storage technologies are eligible for the ITC in a stand-alone capability without being directly tied to otherwise eligible generation.

With this incentive, the central storage question is no longer whether to deploy it, but how much and how fast. As developers and asset owners move forward with battery energy storage systems (BESS), key strategies in system optimization can bolster financial benefits even further.

Walking the IRA’s fine line

In addition to restoring the ITC to its previous 30% level, the IRA created three additional 10% bonus credits to consider:

| ITC Bonus Credit | Incentive | Requirements | | Low-income community | 10% | Qualified solar projects under 5 MWAC and related storage systems located in census tracts with a poverty rate of 20%+; metropolitan areas where the median family income does not exceed 80% of statewide level, or non-metropolitan areas where the median family income does not exceed 80% of greater of statewide or metropolitan area level | | Energy community | 10% | Brownfield sites; coal mines retired after 1999 or coal-fired plants retired after 2009; communities which have (or since 2009 have had) 0.17%+ direct employment or 25%+ local tax revenue related to fossil fuel extraction, processing, transportation or storage, and which have unemployment at or above the previous year’s national average unemployment rate | | Domestic content | 10% | 100% steel or iron produced in the U.S.40% to 55% of the total cost of manufactured product components must be attributable to products mined, produced, or manufactured in the U.S. |

It’s important to identify the right mix of solar-plus-storage or stand-alone storage systems to create a top-performing asset. Look for an engineering, procurement and construction (EPC) partner who can optimize systems with both technologies, keeping tax and financial benefits in mind.

Strategizing augmentation and asset life

Balance control strategies and energy management systems to drive the optimal performance of an asset over its lifetime. Keeping batteries continuously charged at 100% degrades them faster as does failing to cycle them or cycling them faster than designed.

Ultimately, all systems will degrade, but the rate of degradation depends on how the system is utilized. While it’s important to figure out the right time economically to increase or augment a BESS by installing new batteries, the IRA and rapid technology advance mean there now are additional parameters to keep in mind.

Asset owners need to consider whether augmentation is a CapEx or an OpEx expense, which may have varying effects on their overall financial return strategy.

Optimization

Understanding the regional ISO’s rules and regulations can help identify the best use case/revenue stacking scenarios (i.e., energy only, ancillary only, or a combination).

From the start, the asset owner needs to determine the financial metric that best meets their goals because each metric can yield a different optimal design.

In engineering parlance, study the Pareto frontier, which is an optimization tool that leads to the ideal equilibrium between a system’s variables. Look for the optimal design solution that balances size, duration, and the system’s use profile while ensuring that the model aligns with reality. An experienced partner has insights into what every element of a design change costs. Financial modeling should consider not only the initial capital cost, but also the changes in both revenue and operational cost

This kind of analysis for PV-plus-BESS plant design optimization can take advantage of the following four common curves:

1. Lowest LCOE (PV) – Maximum value to offtaker while meeting hurdle rate
2. Lowest LCOS (BESS) – Maximum value to offtaker while meeting hurdle rate
3. Highest ATIRR (PV + BESS) – Maximum value to the long-term owner
4. Highest ATNPV (PV + BESS) – Maximum value to developer on project sale

Example of BESS System Optimization Image: DEPCOM

Driving cost savings

A recent project modeled 15 battery systems with varying technologies and system configurations against local requirements, ultimately saving millions in avoided installation, augmentation, and replacement costs. The team assessed the batteries for price, bankability, power-to-energy ratio (P-rate), design life, cycle life, augmentation costs/schedule, and capacity degradation.

Proprietary analysis determined that traditional nickel manganese cobalt, nickel cobalt aluminum, and lithium ferro phosphate) battery cells would offer neither the duty life nor guaranteed calendar life required to sustain this project’s 25-year lifespan. Instead, they would require costly initial oversizing and multiple augmentations that would create future engineering integration challenges, and may require one full rip-and-replacement over the project’s life.

Optimizing at the start meant anticipated total savings of $19 million over the system’s 25-year lifespan.

Offtake agreements

Fundamentally, offtake agreements are useful in creating revenue certainty. This is a form of risk mitigation that investors and banks require and comes with opportunity trade-offs.

Power purchase agreements and fixed-tolling agreements are great risk mitigators, but with rapidly changing merchant markets there are unique upside opportunities. Decarbonization efforts, intermittent renewable penetration, and increasing grid load at unprecedented rates offer immense economic benefits.

This leads to the question of how best to balance a project’s risk profile with its upside potential/ Choose a partner with experience navigating the equation.

There are ways to design a system to capitalize on diverse market dynamics. Developers can take advantage of riskier merchant markets, or safer offtake contracts, or a mix of both to strike the right risk/reward profile for their project.

Bankable partner

In a perfect world, money could be saved by sourcing from individual component manufacturers, hiring a controls provider to integrate them, and then an EPC to lay foundations and the balance-of-plant. Another entity might even be brought in to maintain and/or operate the asset.

But in reality, unexpected hurdles arise which are outside the scope of individual contracts, especially with new products and technologies. This leaves the owner or developer on the hook financially while contractors point fingers at each other. This lack of a single responsible party eats away at contingency plans, and in many circumstances profits or returns, all of which creates an additional risk that should be considered.

Instead, partner with an integrated PV and BESS specialist who offers deep utility experience. Look for a company with in-house engineering, procurement, construction, and O&M expertise proven to deliver turnkey systems on time and on budget, and that perform as intended. An EPC with its own system optimization tools and know-how can help prevent costly overbuilds and enhance project financial metrics.

Scott Hoyte serves as DEPCOM’s chief technology officer and leads the EPC’s technology and O&M departments. As a project development engineer in DEPCOM’s energy storage division, Walker Wentzler oversees system optimization and design. DEPCOM Power has more than 5 GW of utility solar EPC experience and 2 GW of assets under management. This material has been prepared for informational purposes only and is not intended to provide, and should not be relied upon for tax, legal or accounting advice.

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Before beginning BESS design, it's important to understand auxiliary power design, site layout, cable sizing, grounding system and site communications design.

Demand for energy storage is on the rise. The increase in extreme weather and power outages also continue to contribute to growing demand for battery energy storage systems (BESS). As a result, there are many questions about sizing and optimizing BESS to provide either energy, grid ancillary services, and/or site backup and blackstart capability. Before beginning BESS design, it’s important to understand auxiliary power design, site layout, cable sizing, grounding system and site communications design.

1. Auxiliary power design

Auxiliary power is electric power that is needed for HVAC for the battery stacks as well as control and communications. This sounds deceptively simple for equipment that has no moving parts, yet it is often a moving target, as BESS vendors continue to morph their designs after an order is placed. Therefore, when it comes to auxiliary design, you must be able to answer the following questions:

• Do you want a separately metered utility service for the auxiliary power so the cooling still works if the utility trips their recloser to the BESS? This has been a real-world problem for some sites.
• What voltages are needed – three phase 480 V and 208 V, single phase 120/240 V, or does the equipment happen to come with European-style three phase 400 V and 230 V equipment?
• What is the real design load – sum of all HVAC nameplates?
• How much margin is really in those HVAC nameplate values?
• Is there a smart controller to prevent concurrent start of all HVAC compressors?
• If high hydrogen is sensed and ventilation is triggered to go full on, are the fans staggered by a few seconds to avoid concurrent inrush currents, and does it include compressors?
• For northern located projects, is heating load the peak design issue?
• For the typically large uncertainty, should the aux transformer(s) be provided with fan kits as insurance if the loads end up being larger?
• Should the aux transformer(s) be provided with a fan rating anyway just so that they can be economically downsized?
• What about the little things like lighting and security power?

These are just a few examples of the many questions that must be answered prior to embarking on the auxiliary design.

1. Site layout

BESS site layout can be easy or complicated, depending on the site location, the site owner’s preferences or requirements, and the BESS itself. Some of the main questions to consider for the site layout are:

• Does the BESS vendor have a minimum spacing requirement?
• Does the owner have a minimum spacing requirement?
• How much of a lip do you want on the pad the containers sit on – 6 inches; 2 feet?
• Do you want to be able to fully open both doors on back-to-back containers?
• How do you make the cable runs short and simple?
• Realistic cable sizing

BESS systems usually involve short, high ampacity underground runs from the battery rack containers to the inverters or DC/DC converters. In order to avoid excessive cable derates and resulting in larger cables and costs for short underground runs, you will need to consider:

• Will the owner’s engineer require a design per NEC tables, or is a site-specific ampacity calculation allowable?
• Is the owner open to alternative cabling methods compared to multiple runs of conductors in large conduits?
• Has the vendor clearly identified where power and communications cables enter the enclosures?
• Does the container just take one large feed, or is it split into two separate feeds that land on dual fused disconnect switches inside the enclosure?
• What about future expansion/augmentation battery segments, and how do these get connected?
• Grounding system design

Many BESS sites are relatively small, and substation grounding design methods don’t really apply. So you need to ask, what is the design goal? Depending on how the design is approached, a site can either end up with an expensive mesh grid or a reasonable design to connect all of the equipment, and both will be equally safe.

Additionally, are you concerned about possible Radio Frequency Interference being generated by the BESS? Some vendors require additional methods, such as six additional grounding connections per inverter. Is the BESS located at a 911 Call Center or in a remote area? Answering questions like this will help your design and installation process go as smoothly as possible.

1. Site communications design

Communications are an integral part of BESS design, as it allows for remote data monitoring and/or management, and for the BESS system to communicate with the power grid as well as connect to peripheral components. The following site communications design questions should be answered in order to properly design this aspect of a BESS:

• What items need to be connected?
• Is it a radial connection between containers like string inverters, or does it need an extra conduit run to make a communications loop?
• What sort of data monitoring is there, and how does it communicate back to the owner?
• Does the site point of interconnection control device, such as a recloser, need to be monitored/controlled as well?
• How is the required metering being accomplished, and what does it need to talk to?
• Is a utility connection required, and with what communication method?

Joe Jancauskas is a senior electrical engineer at Castillo Engineering, a design and engineering firm based in Maitland, Florida that offers full service solar and energy storage design, engineering, and consulting services to developers, EPC contractors and utility companies.

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Recruiting more women into the engineering workforce and making more opportunities available in electrical engineering programs will foster true gender equity and help solve our current shortage of clean energy workers.

I could count on one hand the number of fellow female engineers I graduated with from Marquette University. This mirrors the demographics across the country where women account for only 14% of engineers and only 8% of the nation’s electrical engineering workforce.

We’re simultaneously facing another not-so-quiet crisis: our nation is in dire need of more power engineers to do the difficult work of interconnection studies, maintenance, and operation of our quickly fraying electricity grid, which is growing more complex by the day. Gigawatts of renewable energy generation projects are stuck in interconnection queues, waiting for their turn to bring us the cleaner energy system we needed yesterday.

Electrical and power engineers are not the only ones in the energy industry in very short supply. There is also a dire need for more trained electricians to do the critical work of wiring the solar panels, wind turbines, and batteries we need to make the transition to a renewable energy system. The gender disparity is also stark for trained electricians with only 2% of those employed being women.

We can solve both problems at once: recruiting more women into the engineering workforce and making more opportunities available in electrical engineering programs. This will foster true gender equity and help solve our current shortage of qualified people doing the hard work of transitioning our power grid from one dependent on fossil fuels to one built upon a distributed network of non-emitting solar, wind and energy storage projects.

My own path to electrical engineering was successful because of well-timed interventions from adults who saw my potential. When I was in high school, my chemistry teacher noticed that I enjoyed math, problem solving, and science – and he suggested that I attend an engineering camp during the summer. I had a basketball tournament the weekend before camp started, so I put my basketball bag on one shoulder and my camp bag on the other and set off to give it a try. Sure, it was challenging and a bit nerve-racking at first to step into a new experience, but that small leap of faith put me on a career path to working on nuclear power plants, mission critical facilities, airplane screen displays, and now energy storage systems that store solar energy and stabilize electricity grids. Our storage systems help fill the intermittency gap of renewable energy sources – ensuring that the energy captured before the sun goes down can be saved for later, when the demand for electricity rises. Without the nudge to give an engineering camp a try, I wouldn’t have known about the fascinating and impactful engineering careers like the one I have now. Because of preconceptions of what girls can do, we leave so much potential skill and brainpower untapped, and we need everyone onboard to make the energy transition happen.

That’s not to say there won’t be challenges in the way. When I enrolled at Marquette University, I was the only engineer on the school’s basketball team. I wasn’t getting much playing time on the team and engineering proved difficult at times. A few months in, I called my mom, ready to quit both. She gave me the advice I needed to persevere; in basketball, she said to keep up my training and wait it out. Sure enough, by the end of the season, my hard work and dedication paid off and I started getting playing time. During my senior year, I was captain of the basketball team, learning the valuable leadership skills that would serve me professionally for years to come. My mom also encouraged me to find tutoring and a study group for my engineering work. I found other students who stayed as part of my support network for years. No one expects you to know everything all the time. That’s true for school and it’s true once you enter your profession. Find mentors and ask for the support you need.

Engineering careers provide steady, high paying employment. Electrical engineers are going to have plenty of work for decades to come in the energy sector alone. Engineering training also provides highly transferable skills: Henry Ford and Soichiro Honda were both engineers before they went into business and management.

Giving opportunities to girls and young women to attend camps and experience engineering requires involvement from all fronts. First, we must create opportunities for girls in middle school and high school to try Science, Technology, Engineering and Math (STEM). In addition, we need to support young women to overcome the fear that comes with trying something new, especially skills and interests that society has cast aside as “nerdy” or just for boys. It may sound trivial, but that kind of mentality and stereotyping can be a big hurdle in preventing young women from seeing themselves as engineers. So often fear holds us back. It whispers doubt into our ears at every possible turn, keeping us from opportunities that we deserve.

My advice is this: don’t let fear get in the way. That’s not to say things won’t be challenging at times, but I’m living proof that it can and should be pushed through. And I hope to see many more young women enter the field to engineer the renewable energy solutions of today and tomorrow.

Let’s set up young women for the best possible success and show them the immense opportunities that await them in engineering and renewable energy. Get girls inspired, get them the support they need, and let’s ensure that we shine a bright light on the girl power needed to build the clean energy future.

Jasmine Robinson holds a Bachelor of Science in Electrical Engineering from Marquette University and is currently a project manager at IHI Terrasun Solutions, which provides integration, software and services to large-scale energy storage projects.

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Clean Energy Associates (CEA) has calculated the price premium that solar developers will swallow in return for the levelized cost of energy (LCOE) savings offered by the latest generation of high-efficiency PV modules.

From pv magazine March 2023

Developments in PV module technology have accelerated since 2018. The chart above – based on CEA quality assurance data – shows the most common modules for utility-scale projects in 2017, varied by technology, had a glass-backsheet structure and featured 72 six-inch cells – a module type launched in 2008.

Since 2018, we have witnessed the transition from multicrystalline aluminum back surface field cells to mono PERC (passivated-emitter, rear contact) devices; the adoption of half-cut cells; the dominance of bifacial, glass-glass products; the introduction of multi busbar devices; a shift to larger wafers – 166 mm, then 182 mm, then 210 mm; the emergence of gallium doped p-type wafers; and, most recently, the rise of n-type cells – predominantly n-TOPCon (n-type, tunnel-oxide, passivated contact) products.

Wafer sizes grew to reduce costs. Market share today is split between 210 mm and 182 mm wafers as the advantages of each depends on project specifics. As production lines can be altered to produce either size, market share is fluid.

While “exotic” formats such as 218 mm wafers are unlikely to prosper, 182 mm variants have emerged, such as 182 mm wide by 185 mm products designed to minimize white space between cells in the long direction of the module. Trina Solar recently launched a 182 mm wide by 210 mm tall wafer. Ultimately, such variants are dependent on M10 or G12 solar ingot platforms and supply chains.

N-type moves

N-type (negatively-doped) solutions made an impressive entry in 2022 with several gigawatts of TOPCon generation capacity shipped already. TOPCon and heterojunction (HJT) cells are the main high-efficiency contenders to replace mainstream, p-type PERC cells. TOPCon and HJT cell architecture can be applied on p-type or n-type wafers but years of research have convinced manufacturers only n-type TOPCon and HJT variants can achieve an optimum efficiency-cost relationship.

TOPCon leads the race for now as legacy PERC cell production lines can be upgraded to produce it, whereas HJT requires retooling. TOPCon is also cheaper, thanks mainly to lower capital and operating expenditures.

Rival high-efficiency technology, interdigitated back contact (IBC) solar, has been touted as the “end-of-the-road” single-junction silicon PV technology because going beyond 26% conversion efficiency requires tandem cells. IBC cells have their contacts on the rear side, theoretically offering the highest efficiency for single-junction devices. However, front-contact TOPCon and HJT cells can become back-contact devices and several manufacturers appear to have planned such development. Longi, however, has chosen a p-type IBC architecture that probably uses PERC and TOPCon passivation.

The pros and cons of competing cell technologies are summarized in the following table, in which IBC refers to any passivation method, although properties such as bifaciality and tooling capital expenditure (capex) are linked to back-contact cells. An intense effort is under way to reduce the silver content of HJT devices.

Pros and cons of competing cell technologies

| PERC | TOPCon | HJT | IBC | | --- | --- | --- | --- | | Total capex | Low | Medium | High | High | | Opex | Low | Medium | High | High | | Tool supply | Very mature | Good | Limited | Limited | | PERC upgrade | NA | Yes | No | No | | Silver usage | Low | Medium | High | High | | Cell efficiency potential | Low | High | Higher | Highest | | Energy yield:temperature performance | Baseline | Good | Very good | Good/very good | | Energy yield: bifaciality | Baseline | Higher | Highest | Low |

Levelized energy cost

The pace of n-type expansion will rapidly accelerate once technology and cost hurdles are surpassed. Module buyers will accept a price premium on n-type if high efficiency and improved energy yield reduce capex and the LCOE.

To measure such savings, CEA studied a 100 MW system on single-axis horizontal trackers in Spain. PERC and TOPCon cells were compared. Balance-of-system component costs were assumed from several sources, module cost and price data points were taken from CEA’s “PV Price Forecasting Report” and price tracking. PVsyst was used to measure energy yield.

For the analysis, CEA defined a “maximum price premium” metric to indicate the amount a high efficiency module could command over a PERC panel without surrendering LCOE advantage.

CEA equalized the LCOE for PERC and TOPCon systems, deriving the TOPCon module price by adding the maximum premium to the PERC module baseline. Calculations showed TOPCon manufacturers can charge a premium of up to $0.0327/W over PERC without LCOE suffering. While buyers would not pay the maximum premium for zero LCOE advantage, they would pay extra for some LCOE gain. The following chart shows the sensitivity of the LCOE advantage to the price premium, with premiums below 50% of the maximum figure resulting in LCOE advantages of 2.5% or higher. In this scenario, a premium of less than $0.016/W would be reasonable.

The price premium for HJT modules – similarly efficient to TOPCon but with higher energy yield – could be roughly 30% higher than for TOPCon: around $0.005/W. HJT manufacturers must work hard to reduce their cost delta with TOPCon and aim for an efficiency lead.

Modules are lowering the LCOE but pushing past tipping points accelerates the rate of change, making it difficult to estimate development timelines. As a web of factors influence LCOE, manufacturer claims need verification.

George Touloupas is the senior director for technology and quality at solar and storage advisory Clean Energy Associates.

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Solar is wrongly perceived by some people to be an area-intensive energy generation technology requiring much more space than conventional fossil-fuel power plants.

From pv magazine global

The area of solar panel per person needed to provide all required energy is simply estimated. Typically, developed countries such as the United States, Australia and Singapore consume about 10 MWh of electricity per person per annum. This will need to double to accommodate the electrification of transport, heating, and industry. Assuming 22% efficient panels and a DC capacity factor of 17% (averaged across rooftop solar and solar farms), we arrive at a figure of 13 kW per person occupying 60 m2.

The global population is 8 billion, and thus 0.5 million square kilometers of solar panels are required for an affluent, energy-intensive world that is fully decarbonized using only photovoltaics. For perspective, this is 1% of the area devoted to agriculture (50 million km2). Regions with lower per capita energy consumption, and those with substantial wind or hydro resources, will need much smaller areas of solar panel per person.

Solar panels can be mounted on rooftops, at solar farms in conjunction with agriculture (agrivoltaics), in arid areas, on inland lakes (floating PV), and on calm maritime waters. Agrivoltaics and floating PV are growing rapidly, but from a much smaller base than more traditional rooftop or ground-mounted PV.

Agrivoltaics in combination with pasturing costs nearly the same as conventional ground-mounted PV, except that the panel rows might be more widely spaced. The farmer benefits from lease fees and the livestock benefit from shade from the panels. The solar farm company benefits from free grass control. Agrivoltaics in conjunction with cropping usually requires taller panel supports and other adaptations, which add to the cost.

The cost of floating PV is around 20% higher than that of rooftop solar, but can be similar to that of tracking, ground-mounted PV with bifacial modules. This augurs well for rapid future growth. Although the cost of floating PV is currently higher than roof and ground mounted PV, it has large potential in countries with high population density. Many countries have substantial inland reservoirs that can host large solar farms.

The potential for maritime floating PV is enormous. Indonesia’s calm, tropical inland sea has 0.7 million km2 of seascape that never has wind and waves larger than 15 m/sec and 4 m height respectively, which is sufficient for all the solar energy an affluent and fully decarbonized world will need.

The world has 1.3 TW of hydroelectricity capacity, which will be passed by global solar capacity during 2023. This comprises a mixture of run-of-river systems with small reservoirs and large storage reservoirs. Covering 100% of a hydroelectric storage lake with solar panels will typically yield much larger power capacity and annual energy than the hydroelectric system.

One of the largest hydropower plants in the world is Itaipu in Brazil, with a flooded area of 1350 km2 and an installed capacity of 14 GW. The 50-years old plant was part of the country’s foreign debt for many decades (US$63 billion – last instalment paid recently!). Due to water constraints and eutrophication, only 66 TWh of electricity was generated in 2021 (compared to a record 103 TWh in 2016). If the Itaipu lake were completely covered with PV modules, the installed capacity of this giant PV power plant would be 270 GW (nearly 20 times Itaipu’s installed capacity), and it would generate some 350 TWh of electricity per year (more than five times Itaipu’s 2021 production), accounting for over 70% of the Brazilian annual electricity consumption.

It took 10 years to build Itaipu, and another 10 years to bring it to full capacity. Fifty years after the Treaty of Itaipu was initially signed, it is the country’s largest “battery,” and solar PV on rooftops and on the ground benefit tremendously from this large baseload modulator. Brazil allowed solar PV to be connected to the grid only in 2012, and 10 years later reached an installed capacity nearly twice that of Itaipu (18 GW of rooftop PV and 8 GW of large-scale, ground-mounted PV as of February 2023).

Rooftop solar

Rooftop PV is the fastest growing segment of the global energy market. Rooftop PV is behind the energy meter and competes with retail electricity tariffs, which are typically much higher than wholesale tariffs. Households and companies provide the funding and assume the risk, which avoids the need for public debt.

In Australia, about one third of residential dwellings have rooftop PV. Continued rapid growth in rooftop PV is expected because most houses and commercial buildings will eventually install PV systems. An important trend is the repowering of earlier systems: houses upgrading PV systems from 2 kW to 4 kW to 8 kW to 15 kW each. Large-scale home storage to increase self-consumption is available in the form of electric vehicle batteries, home batteries and hot water storage tanks. Australia’s electricity grid remains highly stable despite dire predictions from a decade ago.

High photovoltaic conversion efficiency is key both to reducing prices and reducing land use. Efficiency has improved around fourfold since the 1950s. The first practical Si solar cell was presented in 1954, with an area of about 3 cm2. It was around 6% efficient (60 Wp/m2 at STC) and cost US$286/Wp, more than a thousand times the current price of large-area Si solar modules.

Nearly 70 years later, individual best-of-kind Si solar cells approach 27% efficiency, and commercially available Si solar photovoltaic modules are close to 24% efficient (240 Watts per m2). Commercial Si modules might reach 26% in 2030. Tandem cells have higher efficiency potential than Si cells. However, there are formidable technical and commercial obstacles, including unstable device efficiency. If these can be overcome, then 30% efficient tandem cells may become available. The required area of solar panel for a fully decarbonized energy intensive economy would drop from 60 m2 to 45 m2 per person.

Electricity demand in developing countries is much lower than in developed countries (Bolivia, Brazil, and Chile respectively 1.6, 2.5 and 4.1 MWh per capita per year). For many reasons, it is debatable whether and when energy consumption will reach the level of more affluent countries. Important drivers of future clean energy consumption include private vehicles, electrification of industrial heating, production of hydrogen atoms for the metals and chemical industry, and production of synthetic aviation fuels. Solar PV can be the energy source for all of this, and there are no area constraints in most countries.

Authors: Professor Andrew Blakers (ANU) and Professor Ricardo Rüther (UFSC). ISES, the International Solar Energy Society is an UN-accredited membership NGO founded in 1954 working towards a world with 100% renewable energy for all, used efficiently and wisely.

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Five tips to help your customers make informed decisions about adding energy storage to their homes.

For those not immersed in the space, energy storage systems (ESS) can be a tricky concept to understand. As an installer, it’s critical to effectively communicate the many benefits of ESS to customers, to assist them in making an informed purchase decision that best suits the needs of their home.

Here are five communications tactics installers can adopt to help guide sales conversations:

1. Highlight how ESS help the customer and the planet

One of the most desirable features of energy storage systems is the ability to save energy for later use, whether it be for power outages or to cut costs during peak hours of energy consumption. In states like California, the grid can sometimes be unreliable due to factors like wildfires, earthquakes, and other natural disasters. With ESS, customers can store energy for later use, which is beneficial in situations like the above where an extended power outage is anticipated.

Customers should also understand that ESS serve a greater purpose than backup power generation. Some energy storage systems can also be easily installed and AC-coupled with an existing solar system, helping homeowners cut costs daily and help benefit the planet through using clean energy. Customers with a time-of-use plan can decide when, where, and how their energy is used to offset peak periods when energy costs are the highest.

1. Capitalize on financial incentives

A major piece of legislation we saw come from last year was the Inflation Reduction Act of 2022. This legislation permits homeowners to claim a 30 percent tax credit on eligible energy storage installation projects, even when paired with an existing PV system, and filed with the IRS. The IRA allows this benefit through 2032. The residential battery system tax credit is currently uncapped. Since the current market has such a demand for energy storage systems, we can potentially see additional incentives at both a state and federal level.

Beyond the Inflation Reduction Act of 2022, many states already have, or are planning to implement, ESS-related incentives. New Jersey and Massachusetts already have plans in place, and New York proposed a roadmap to achieve 6GW of energy by 2030. California has long been the hallmark to adopt clean energy solutions.

In December 2022, the California Public Utilities Commission passed a proposal that greatly reduces the amount of potential savings for solar system installations without storage. Due to the passage of this proposal, as of April 13, 2023, grid-tied systems in California will rarely be installed without an ESS.

1. Promote three “easy” points

Some customers might not fully grasp the concept of energy storage systems. In these instances, highlight three easy points – ease of installation, ease of use, and easy on the eye. Since some ESS can be AC-coupled and paired with an existing solar system, or can be connected directly to the grid, they are much quieter when compared to traditional fossil fuel or diesel generators. They’re also much easier on the eye since many designs are sleek, quiet, and floor-standing, wall-supported – meaning they mesh better with their surroundings and are more aesthetically pleasing.

1. Brush up on national trends

It doesn’t require a lot of research to see the market’s explosive growth in energy storage systems usage in recent years. With an increase during the past decade in lithium-ion production, ESS have become much more attainable for residential and commercial applications. While setbacks like pandemic-induced supply chain issues have occurred, according to American Clean Power, the ESS market saw continued growth in the last quarter of 2022–the biggest quarter ever for clean energy installations. The demand is there for energy storage systems, and for many potential customers it’s only a matter of time before they decide to purchase. During this time, installers should take the time to educate would-be ESS customers and capitalize on national trends to help customers make informed purchase decisions.

1. Reiterate cost savings

Cost savings are a key factor in the market’s explosive growth in energy storage systems. When communicating with customers, be sure to highlight the ongoing savings they will see, and provide them with resources to compare quotes. Resources like EnergySage offer free and detailed advice to help find the right installer.

Be sure to communicate with your customers the long-term savings they are likely to see from ESS and develop a close-knit relationship with manufacturers to effectively communicate key features of the product.

Chris Canfield is the Director of ESS Sales at LG Electronics USA. The LG Electronics Energy Storage Systems business represents a fast-growing new area for LG in the United States, leveraging the company’s renewable energy expertise to unlock value for customers and plug into the new era of sustainability. Based in Englewood Cliffs, N.J., LG Electronics USA Inc. is the North American subsidiary of LG Electronics Inc., a $63 billion global innovator in technology and manufacturing.

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The CPUC, California legislature and other authorities having jurisdiction must address these issues or risk constraining jobs, CO2 mitigation, and clean energy deployment.

Think of a wine bottle and how it gets narrower at the spout, slowing down the flow. That narrow area is called the bottleneck, which is also a common engineering expression for project obstacles. A wine bottleneck is a great visualization of what’s happening to small-scale utility and community solar developers in California.

While California still leads the nation in solar deployment, project developers face unique bottlenecks that are slowing the flow of meeting the state’s ambitious goal of achieving net zero carbon pollution by 2045.

Before we get into our four main bottlenecks, let’s define small-scale utility projects as being between 1 MW (AC) and 20 MW (AC) and located near the communities that they serve. These types of projects can serve California’s Community Choice Aggregators (CCAs), investor-owned utilities (IOUs), as well as future community solar customers.

More recently, California passed the Community Renewable Energy Act, finally setting the stage for a viable community solar and energy storage market in the state. Now, the California Public Utilities Commission (CPUC) has the challenge of designing the program in a way that attracts both community solar developers and subscribers.

But even with a well-designed community solar program, the local solar bottlenecks will remain. In our experience developing over 250MW across 35 small-scale local utility solar projects in California, the following four bottlenecks are slowing down the clean energy flow.

Bottleneck #1: Interconnection backlogs

Connecting projects to the grid is one of the biggest challenges across the United States. Renewable energy and storage projects can get stalled in long interconnection queues for years, which results in about 75% of them dropping out. Many projects are never even considered because of these issues.

Projects in California face additional interconnection obstacles. Because the state has high renewables penetration, it can be challenging to find locations on the grid that have enough capacity for additional solar generation.

For this reason, a utility may require that developers provide upgrades to a substation, distribution line, or transmission line before connecting a project to the grid. The cost and timeline for construction of these required upgrades in many instances make projects infeasible, and then they die. Delays at this stage can be compounded by constrained supply chains and long lead times for major equipment needed to make the upgrades.

An experienced solar developer can identify locations that already have enough capacity and don’t require upgrades, but the process doesn’t stop there. Once you have identified a viable location for your project, you still need to navigate the complex utility interconnection process. In California, that includes going through several interconnection studies that can be cumbersome and tough to navigate efficiently.

Projects over 1 MWac in California face an extra interconnection step. As part of the California Independent System Operator’s (CAISO’s) New Resource Implementation (NRI) process, developers need to design a Remote Intelligent Gateway (RIG) and implement it on the site. This lengthy, multistep process can be especially challenging for inexperienced developers and takes specialized engineering resources to complete. Missing any one of the many required submissions can delay your project significantly.

This bottleneck tends to slow projects even further due to utility workforce issues – the utilities haven’t staffed up to meet the continued demand of renewables trying to connect to the grid. Because interconnection is so complex in California, utilities need experienced staff that thoroughly understand the process. Unfortunately, many California utilities are understaffed and experience can only happen over time. Consequently, even with all our interconnection t’s crossed and i’s dotted, utilities can be slow to move our distributed projects through their queue.

The solution for us has been to maintain strong utility relationships and attention to detail, carefully providing all the requirements and avoiding further questions or changes. You have to actively manage up to push things through.

Bottleneck #2: Permitting

Efforts are being made across the U.S. to streamline and standardize solar permitting. But California remains one of the most challenging states in this regard.

Permitting processes vary throughout California. Developers have to adhere to different requirements for each local jurisdiction, whether a city or county. That complicates the process for any developer working in more than one city or county.

That said, what all the jurisdictions have in common is a requirement to follow the California Environmental Quality Act (CEQA) process for reviewing projects and determining their potential environmental impact.

The lengthy CEQA process can require many subject matter experts and consultants, which often presents another bottleneck for developers. While some items assessed in this standardized process are straightforward and clear, CEQA also considers factors like visual and agricultural impacts that are somewhat subjective.

The only true solution here would be to pass legislation that streamlined permitting for renewables and mandated statewide permitting standards that would apply to all authorities having jurisdiction (AHJs), cities, and counties.

Bottleneck #3: Land use considerations

Impacts to agricultural land are a common concern. As community solar and local utility solar projects gain popularity around the country, concerns like these are making it more challenging to find appropriate sites for them.

This issue is especially significant in California, which is home to some of the most productive agricultural land in the U.S. For this reason, the state has taken steps to preserve farmland through both CEQA and the Williamson Act, a program that allows specific parcels of land to be restricted to agricultural use in exchange for reduced property taxes.

As a result, California solar developers aim to either avoid building on prime agricultural lands or mitigate the potential impacts of projects on these lands. These restrictions mean that California has significantly fewer viable sites for local solar development.

To open this bottleneck, California or other AHJs could recognize that solar is a temporary, low-impact use and that at its core, solar is preserving land, not permanently impacting it. Unlike building an industrial building on site or paving a large parking lot, solar developers have a decommissioning plan that removes the system and restores the ground to its original condition. To codify this difference, the State should create a decommissioning standard of care for solar built on prime agricultural lands, enabling more sites to open up throughout California.

Another solution for land use concerns would be the State providing incentives for agrivoltaics. This dual use of farmland can increase production for crops that do better with some shade and can decrease water use, a key benefit in California. Agrivoltaics also compensates farmers for the use of their land, providing an additional income stream. Solar panels can also be sited on unproductive parts of a farm, increasing the farm’s income without disrupting their operations.

Another land use approach that Renewable Properties has implemented at many sites is planting pollinator vegetation alongside solar panels, increasing yields for farms throughout a region. Additionally, the grazing of small livestock is another alternative that enables farmers to continue their operations alongside a solar project.

In the end, we’ve found that AHJs that prioritize renewables will find ways to solve land use bottlenecks with solutions that satisfy all stakeholders involved.

Bottleneck #4: Workforce constraints

With the passage of the Inflation Reduction Act (IRA), the limited supply of skilled workers has become a huge bottleneck for all solar developers, large and small. California could solve all of its current supply chain, permitting, interconnection, and financing bottlenecks, but without increasing the local skilled workforce, projects cannot be built and will face delays.

The IRA requires that for solar projects larger than 1 MW to receive the full Investment Tax Credit or Production Tax Credit, developers must pay prevailing wages. This requirement supports small construction businesses and allows them to operate as part of a union or right-to-work entity. However, there aren’t enough classes and experienced trainers in California to take advantage of these provisions.

One answer is for California and local communities to incentivize attracting solar energy workforce development in their community colleges, labor unions, and trade organizations. Of course, even with incentives, those worker training programs require skilled and experienced teachers who are needed and working out in the field.

The good news is that if you’re looking for a job, the renewable energy industry is actively hiring and in need of skilled labor across a variety of trades – construction, electrical, civil, engineering, legal, accounting, finance, permitting and land. If you’re talented and have a conviction for fighting climate change, the renewable energy industry is open for business and welcomes you!

Opening up the bottlenecks

These four bottlenecks in California can be frustrating, and Renewable Properties is doing everything we can to advocate for better policies and to open up the solar development flow before California’s new community solar program goes into effect. But we can’t do it alone.

We urge the CPUC, California legislators, and local AHJs to review these four bottlenecks and to rapidly apply changes that will streamline local solar development throughout California. If they don’t act this year, then the bottlenecks will become even more severe, constraining jobs, CO2 mitigation, and clean energy deployment.

Climate change is a global problem that requires local solutions. Solving these bottlenecks is California’s opportunity to continue leading and to be part of the solution!

Aaron Halimi is the founder and CEO of Renewable Properties, a small scale utility and community solar developer and asset owner operating in 15 states and headquartered in San Francisco.

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Do the lowest-cost modules always deliver the highest project value?

Consider the two module options below and how you would go about making a selection for a 49 MW DC solar project.

• Option A — 540W module at 0.426 $/W
• Option B — 650W module at 0.469 $/W

While making a decision strictly based on the dollars-per-watt ($/W) of a PV module may be a general rule for many project developers and independent power producers (IPPs), this approach fails to consider both the effect that module selection can have on balance of system (BOS) costs, as well the long-term impacts of module selection on project revenue.

Maximizing the value of a PV project is a balancing act. Estimated financial returns can change as modules are analyzed based on their prices, energy yield and degradation rates along with BOS costs. Any of these can tip the scale from a low-cost, lower-wattage module to a more expensive, larger-format module — and vice versa.

The secret to understanding how module costs affect project value lies in the formulas used in your financial analysis and your specific installation details. While experienced module buyers are familiar with the steps and considerations to take, even the most seasoned players can benefit from some guiding strategies to navigate the ever-changing procurement process.

Understanding net present value
You can use product data to compare the value of different modules to optimize overall project value. Determining each module’s net present value (NPV) is best. NPV calculates an asset’s costs and projected income and assigns a present-day value, accounting for the fact that money has greater value now than it will in the future, a concept known as the time value of money. NPV is calculated by summing up annual cash flows and discounting them back to today’s dollars. Employing NPV is more valuable than selecting modules based on the lowest cost, or even lowest all-in $/W cost, because it accounts for the total costs and revenue over the asset’s life.

Consider these two optimization levers in your financial analysis:

• CapEx levers: Any deltas in module costs must be weighed against potential effects on balance of system (BOS) costs. For example, larger-format modules will act to reduce the total module count, but their impact on the number of racks and foundations will vary depending on the racking product and the site wind and snow loads. A lower open circuit voltage (Voc) increases the allowable string length, which decreases the total number of strings and the total length of DC source circuit wiring. Frame thickness may necessitate larger, more expensive clamps or more robust racking structures. It is common for the additional costs associated with these countermeasures to be 0.015 $/W or more.
• Revenue levers: The revenue produced by a project, either through the sale of energy or through tax incentives, is primarily based on the system’s production. Module selection can significantly affect energy production due to differences in specific yield and module degradation. Bifacial modules at a project site optimized for rear-side production can easily increase output by 5%. Loss factors related to low light, temperature, incident angle modifier (IAM) and light-induced degradation (LID) can result in performance deltas of 2% or more between modules. New cell technologies will further differentiate the highest and lowest-performing modules.

Real-world proof

While choosing the lowest-cost option or a large format module may seem more attractive, real-world projects prove this is only sometimes true. In reality, you could be leaving money on the table, as outlined in the examples below.

Case Study #1

System size: 49 MW DC

Racking type: Single-axis tracker

Location: Peoria, Ill.

Table 1 – module options summary

| Module | Watts | $/W Module Cost | NPV Delta ($) | CapEx Savings ($) | Revenue Delta ($) | | Module A | 650 W | 0.469 | – | – | – | | Module B | 540 W | 0.426 | -1,109,935 | 293,000 | -1,402,935 |

Even though there was a $2.1M (0.043 $/W) module cost advantage for the 540W module, there was only a $293,000 (0.006 $/W) difference between the two modules in the all-in CapEx costs to build the project. This was due to a $1.8M (0.037 $/W) pickup in BOS cost for the 650W module over the 540W module. The 650W module was also projected to produce revenue that was $1.4 million higher than the 540W module on an NPV basis. When module costs, BOS costs and revenue were combined, the analysis showed a project built with the 650W module would have a higher NPV. In this example, selecting the lower-cost 540W module would have reduced project NPV by $1.1 million.

Table 2 – module, row, foundation & string quantity comparison

| Module | Watts | Modules (Qty.) | Modules per String | Modules per Row | Rows (Qty.) | Foundations (Qty.) | Strings (Qty.) | DC Source Circuit (ft) | | Module A | 650 | 75,240 | 30 | 90 | 836 | 15,884 | 2,508 | 752,400 | | Module B | 540 | 90,500 | 25 | 100 | 905 | 17,195 | 3,602 | 1,086,000 |

A project built with the 650W module requires installing far fewer modules, tracker rows and foundations. This is largely due to the form factor of the 650W module, but the Voc of the module also plays a role. The 650W module has a Voc of 45.0 vs. a Voc of 49.8 for the 540W module. This allows a maximum string length of 30 for the 650 and a maximum string length of only 27 for the 540s. When considering the physical length limitations of the tracker and the best practice of installing a whole number of strings per tracker row, it’s possible to maximize the number of modules per row by using three strings of 30 for the 650W, but it’s necessary to drop to four strings of 25 for the 540W. As a result, using the 650W results in more watts per row (4.5kW) and requires almost 1,100 fewer strings and over 300,000 less feet of source circuit wiring.

Running performance models for these two modules shows that the 650W module has a yield advantage of 2% over the 540W module. This yield advantage is a result of lower IAM, low light and temperature losses. Based on the energy rate for this project, the project term and the assumed discount rate, the revenue produced by this 2 percent increase in production has a net present value of $1.2M.

The 650W module also has a warrantied annual degradation rate of 0.45 percent, compared to the higher 0.5 percent annual degradation rate of the 540W module. In this case, the additional lifetime energy production that results from the lower degradation rate increases the NPV of the revenue by an additional $200,000. With both factors combined, the 650W module is projected to increase revenue by $1.4M based on NPV when compared to the 540W module.

Case Study #2

System size: 5 MW DC

Racking type: Fixed tilt

Location: Central Massachusetts

Table 3 – module options summary

| Module | Watts | $/W Module Cost | NPV Delta ($) | CapEx Savings ($) | Revenue Delta ($) | | Module C | 540 W | 0.443 | – | – | – | | Module D | 650 W | 0.485 | -147,178 | -155,000 | 7,822 |

Based on the first case study, it’s easy to assume that the best option would be the large-format 650W module. However, this project uses different modules than the first example, so the NPV of the 540W module was higher by $147,000.

Table 4 – module, row, foundation & string quantity comparison

| Module | Watts | Modules (Qty.) | Modules per String | Modules per Row | Rows (Qty.) | Foundations (Qty.) | Strings (Qty.) | DC Source Circuit (ft) | | Module C | 540 | 9,234 | 27 | 22 | 420 | 1,680 | 342 | 102,600 | | Module D | 650 | 7,685 | 29 | 18 | 427 | 1,708 | 265 | 79,500 |

In the first case study, the 650W module had an advantage in effectively using the tracker rows and foundations. Looking at Table 4, the 650W module requires slightly more tables and foundations for this fixed tilt project. This is based on the physical limitations of the racking product and the number of modules that can be installed per table. There is also a difference between the two options in the “modules per string” metric, which is not as large. The result is that the BOS savings for the 650W module are only 0.011 $/W, compared to the 0.037 $/W savings in the first project. Performance models for this project show an energy delta of 0.12 percent, in favor of the 650W module. This, combined with the fact that both modules have warrantied annual degradation rates of 0.5%, results in only a $7,822 (0.002 $/W) revenue delta between the two modules on an NPV basis.

In this case, the BOS improvements and revenue advantage of the 650W module are not enough to offset the low cost of the 540W module.

Don’t leave money on the table

During module selection, it can seem easy to narrow your focus to a simple comparison of the $/W cost of the modules. However, if your view is limited to module costs, you will be unable to account for changes to total project cost and revenue that a more comprehensive analysis would be able to demonstrate.

Gathering data and performing financial analysis can be time-consuming and laborious. It may require hiring additional procurement or engineering staff, contending with limited access to supplier data that quickly grows out of date and vetting the results. The good news is that new technology solutions have come to market to compare available inventory from top-tier suppliers. Such technology that can help perform module technical analysis enables users to make informed decisions in a timely fashion and secure contracts quickly based on pre-negotiated supply agreements.

However you choose to proceed, a proper analysis that goes beyond module cost is critical to making informed decisions to optimize revenue and realize better project returns.

Tarn Yates Image: Anza

Tarn Yates is director of performance engineering and optimization at Anza, an intelligent renewable energy procurement marketplace born from Borrego. Anza provides developers, IPPs, and EPCs with a software solution to accelerate projects and maximize their returns.

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NEM 3.0 takes effect on April 15. For customers who don’t qualify, or don’t get an application submitted in time, developers need to be ready to implement more solar and storage projects down the line.

California’s electricity bills are already about 5% higher than the national average, and rising. Rate hikes went into effect in January and Southern California Edison proposed another 4.4% increase that would be effective this summer.

California has also become the largest solar market in the United States, seeking clean and affordable energy alternatives, and has been among other states trying to increase the value of clean energy assets with net energy metering (NEM).

The first two iterations of California’s NEM program greatly incentivized the adoption of solar, but NEM 3.0, which was approved unanimously by the California Public Utilities Commission (CPUC) in December, is about to roll that value back. NEM 3.0, which takes effect on April 15, could significantly alter California’s solar landscape.

Let’s dive into the history behind California’s NEM program, and what developers need to grapple with as this new policy is implemented.

How did we get to NEM 3.0?

California’s NEM 1.0 policy ran on a 1-to-1 incentive ratio, meaning for every one kilowatt-hour (kWh) of energy generated from solar, customers were given one kWh of utility-generated credit that could be applied to their energy bills.

In 2017, the CPUC replaced that with NEM 2.0, which redesigned the incentive program to include non-bypassable charges, which were additional charges determined by the amount of kWh of electricity customers consumed from the grid. These additional charges were used to fund important low-income and energy efficiency programs. Although non-bypassable charges decreased the value of solar, credit for exported solar energy was still offered based on retail electricity rates.

When California made the decision to switch from NEM 1.0 to NEM 2.0, few imagined that the state would soon pass another overhaul of the incentive program. Now the landscape is set to shift again.

What changes are coming with NEM 3.0 — and why?

The most significant change under NEM 3.0 is that the value of credits for excess solar exported to the grid will be reduced by roughly 20% to 40% from what is currently being received under NEM 2.0, further decreasing the value of solar. Additionally, under NEM 2.0, customers could lock in retail rates for 20 years, but with NEM 3.0, customers can only lock in rates for nine years. After those nine years, the rate is calculated each year via the Avoided Cost Calculator (ACC) – essentially, customers will get credited the avoided cost, or the wholesale rate of energy at that specific time that the utility would have otherwise paid a supplier for.

Why the changes? For one, the CPUC believes that NEM 2.0 negatively impacts non-participating ratepayers — particularly those with lower incomes. Furthermore, NEM 3.0 could be seen as a vehicle to encourage the adoption of storage. Currently, the solar power produced during the day does not correspond to the periods of peak electricity demands that come at night when customers are home, resulting in the higher consumption of traditional energy sources during peak hours. Since California offers time-of-use rate structures, which are required to participate under NEM 3.0, electricity costs during these peak periods will be very high, but storage can save solar energy generated during the day and use it to power homes and businesses during peak demand.

With the decreased value of solar coming under NEM 3.0, implementing storage to offset the lost value will be a natural next step for customer-generators. This allows customers to avoid paying exorbitant electricity rates that come at peak hours, and lowers their usage of fossil fuels, helping the state meet its goal of slashing carbon emissions to 48% below 1990 levels by 2030.

How should you prepare for NEM 3.0?

Commercial solar customers that don’t already participate in NEM 2.0 have an opportunity to avoid the changes in NEM 3.0: If they submit an interconnection application for the program by April 14, they can be grandfathered into NEM 2.0, locking in retail rates for the next 20 years. If the application is approved, projects must be built and operational within three years to receive NEM 2.0’s benefits.

Those looking to participate need to act fast, getting necessary paperwork together and interconnection applications submitted to ensure they are processed and approved in time. However, commercial customers and some smaller developers may not have the resources and time to get the necessary documentation, such as detailed design documents and project drawings, across the finish line. Therefore, enlisting expertise from more experienced developers or partners who are familiar with the process can be a wise choice.

The chance for customers to retain higher value for their solar projects will create a rapid influx of projects looking to come online under NEM 2.0. With this in mind, developers and customers must be aware of the possible roadblocks that could arise during implementation — there could be interconnection queues or permitting delays. Developers need to apply the right planning on the back end to account for unanticipated roadblocks, as well as ensure they have the necessary labor and materials to build the projects, especially considering potential labor shortages and current supply chain disruptions the industry is facing.

For customers who don’t qualify, or don’t get an application submitted in time, developers need to be ready to implement more solar and storage projects down the line. In the short-term, NEM 3.0 will impact solar adoption, but with time the market will adjust and customers will shift focus to solar-plus-storage deployment to achieve the best value. Even though customers are getting reduced credits for their system under NEM 3.0, adding storage can help balance the overall cost impact on electricity bills. Even implementing things like EV charging infrastructure can be leveraged for vehicle-to-grid charging applications, providing power back to the customer from an EV battery during peak electricity demand periods.

California is at the crossroads of significant electricity related challenges such as high energy costs and grid constraints, and a transition to clean energy. Ultimately, adding storage capabilities could incentivize businesses to go solar, and significantly change the nature of projects across California while also meeting climate goals and increasing grid reliability. A solar-plus-storage market is already a norm in places like San Diego, and developers should be ready for that trend to continue across the state.

Pari Kasotia is senior director and head of policy at DSD Renewables, a solar developer that has hundreds of projects nationwide, and tripled in growth since 2019.

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With electric vehicle (EV) adoption set to turbocharge demand for rare earth elements in Canada and in the United States this decade, attempts are being made to loosen the region’s dependence on China for the sourcing and processing of such critically important energy transition materials.

From pv magazine global

With the electric vehicle market expected to drive demand for 200,000 tons of rare earth elements in North America through 2030, work is being put in by industry and policy makers to restore the region’s rare earth element supply chain.

Efforts are being made in Canada and the U.S. to shift dependency away from Chinese rare earth element reserves. There are many reasons why North America is looking to onshore its processes, one of the biggest being concern around potential supply chain choke points in the event China decides to cut off rare earth element supply due to geopolitical wrangles.

Demand for the material is expected to skyrocket, with an estimated 315,000 tons of rare earth elements needed by 2030, most of them for EVs.

What is being done by North American mines to ensure they can keep up with demand without needing to rely on Chinese rare earth element supply and Far Eastern separation facilities? What type of government policy needs to be implemented to help speed the onshoring process along?

Mountain Pass

Las Vegas-based MP Materials owns the only operating rare earth mine and processing facility in the U.S. The Mountain Pass Mine, in California, is an open pit site that supplied 15.8% of the world’s rare earth production in 2020. In late April, MP Materials began construction at its first rare earth metal, alloy, and magnet manufacturing facility with the intention of fully restoring the U.S.’ rare earth magnetics supply chain. The plans include establishing hydrometallurgy and separation facilities, along with the manufacturing fab, at a site expected to be completed in 2025. Becoming a closed-loop operation that can convert refined materials into metals and alloys would mean the company would no longer have to export its mineral concentrate material to China for processing, thereby onshoring the process and decoupling the current supply chain.

MP Materials’ substantial, $700 million investment is the first of its kind in the U.S. and would be able to produce approximately 1,000 tons per year of neodymium-iron-boron (NdFeB) magnets, thereby supporting the production of approximately 500,000 EV motors, with room to scale. In addition to electric vehicles, NdFeB magnets are used in robots, drones, defense systems, wind turbines, and many other high-growth technologies.

Mine progress

Just before construction began at the mine, MP Materials was awarded $35 million by the U.S. government’s Department of Defense to refine and separate heavy rare earth elements to further support onshoring of both the mining and processing procedures. At around the same time, MP Materials and General Motors (GM) announced a definitive supply agreement for Mountain Pass to produce alloys and magnets for GM’s electric vehicle programs. Under the long-term contract, MP Materials will supply U.S.-sourced and manufactured rare earth materials, alloy, and finished magnets for the electric motors for more than a dozen GM models, with a gradual production ramp expected to begin late this year, starting with alloy supply.

This means that not only will Mountain Pass be expected to produce enough rare earth elements to fulfill the Pentagon’s Department of Defense requirements, it must also meet the alloy requirements needed to make electric motors for GM. How is this all possible without significant government support?

More help needed

Although tremendous efforts have been made to begin decoupling supply chains from China, to shift processing to onshore facilities, there is still a significant gap between domestic supply and demand. One solution to this which U.S. president Joe Biden and Canadian prime minister Justin Trudeau should consider is the creation of upstream investment incentives for suppliers of these critical minerals – particularly the metals needed for EV motors.

In late December, the Canadian government published a strategy to increase the responsibly-sourced supply of 31 critical minerals. It was backed by $3.8 billion in the 2022 budget, including $40 million to support northern regulatory processes and a 30% exploration tax credit for targeted minerals.

The issue is that these budget promises are currently no more than smoke and mirrors. Brandon Macdonald, CEO and director of Canadian miner Fireweed Metals, says he would like Ottawa to extend flow-through tax credits as there is capital scarcity during the lengthy permitting process for mining.

Flow-through shares

Flow-through shares are stock issued by mining companies at a higher price than common shares. The issuer agrees to forego, on flow-through shares, the tax deductible benefit due under Canadian law that is associated with mining exploration and development. Instead, investors buying flow-through shares can themselves claim those tax deductions, with such stock helping miners raise finance during capital-intensive exploration efforts.

Macdonald is also calling on the Canadian government to invest in infrastructure including roads, power grids, smelters, and refineries. Although Ottawa’s strategy is meant to accelerate strategic projects, build sustainable infrastructure, and make assessments more efficient, if the right companies – the ones uniquely positioned to begin fulfilling national demand within a couple of years – are not supported financially, the nation could be no closer to decoupling supply chains in 2025 than it is today.

Policy wishlist

Much work remains to be done to onshore North America’s rare earth element supply chain.

If the U.S. and Canadian governments explore different incentives for junior mining companies, the sector could see expedited infrastructure and supply chains decoupled from China becoming a reality much, much more quickly. The time to act is now, given rare earth element demand is expected to soar as North America looks to reduce its carbon footprint by rolling out EVs at mass scale.

Ultimately, the grip China has over North American supply is expected to loosen over time, particularly as new mines such as Mountain Pass come into full operation, but onshore rare earth processing could be further accelerated with the help of proper government funding and support from policy makers.

The world outside China needs more rare earth element mines and processing and separation facilities in order to reduce its dependence on the Far East for critical minerals.

About the author: Dr. Luisa Moreno is president of Vancouver-based rare earth miner Defense Metals Corp. She is a physics engineer with a PhD in materials science and mechanics from Imperial College London, in the UK. She is known as a leading analyst in rare earths and has published several reports and articles for the investment community. Dr. Moreno has co-authored a book on mineral processing and project financing and authored a number of advanced industry and technical reports on several technology minerals.

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The requirements for distributed energy resources (DERs) are rapidly evolving, including those for DERs using solar photovoltaic (PV) systems. This second installment in a series on evolving standards details the code and additional safety requirements for the connection of direct current PV circuits to inverters.

In the first article of this series, the evolution of UL 1741 was outlined, including updates to IEEE 1547. It’s also relevant to understand the specific safety requirements regarding how PV circuits connect to inverters. These additional safety requirements are necessary to comply with the National Electrical Code (NEC). Three topics will be discussed in this article: PV direct current (DC) ground fault, PV DC arc fault and rapid shutdown.

The NEC, also known as NFPA 70, governs all electrical installations in the U.S. The National Fire Protection Association (NFPA) first published the code in 1897, which is now revised every three years. Conceptually, this code could be a uniform standard across the nation. In practice, individual states determine when to adopt any version of the NEC, creating a varied patchwork of regulation based on location.

The current adoption status is tracked by the NFPA – a regularly updated enforcement map of the U.S. can be found here.

This map illustrates that as of December 1, 2022, shortly after the publication of the 2023 edition of the NEC, only 25 states were enforcing the 2020 edition of the NEC, with all others enforcing an older edition. Article 690 in the NEC is focused on PV systems. This article first appeared in the 1984 edition of the NEC, 15 years before UL 1741 was published. The three topics of this article come from NEC article 690: PV DC ground faults are covered in NEC 2020 section 690.41(B), PV DC arc faults in 690.11, and rapid shutdown in section 690.12.

Ground fault detection

PV DC ground faults, in either positive or negative circuits, can happen for many reasons. Factors can include manufacturing defects, installation methods, rodents, project age combined with environmental stresses, and degradation of materials. Innovation in technology and materials has reduced these issues, but there is still risk. Reductions in the number of DC connections and improvements in wire management methods can further reduce ground fault occurrences.

PV DC ground fault detection is an important safety feature that indicates when either the positive or negative conductor unintentionally establishes a lower resistance (fault) path to ground. This can become a hazard because the fault can allow current flow through the fault path, often consisting of exposed conductive parts of the PV system. Originally, PV inverters were designed with transformers to boost converted alternating current (AC) voltage to the higher utility service levels. This transformer provided galvanic isolation of the DC side of the PV system from the AC conductors of the premises wiring system and its grounding electrode system. Because the PV array DC circuits were referenced to ground on the DC side of the inverter, the first ground fault detection was simply detecting current flow through the DC ground reference, such as by a fuse in the ground reference path.

The rapid adoption of transformer-less inverters coincided with concerns about fuse-based ground fault detection. Once the transformer was removed, the fuse-based method of ground fault detection was not possible since the PV array DC circuits could no longer reference the ground on the DC side of the inverter. To work with the transformer-less inverters, a two-part ground fault detection system was developed. This system verifies high resistance of both PV conductors to ground and monitors residual current for leakage.

The improved method more readily identified faults and changes that indicate PV system degradation. The updated detection method was incorporated into UL 1741 as a Certification Requirements Decision (CRD) for smaller non-isolated systems in 2010.

Key Take Away: Robust, sensitive ground fault protection tailored to transformer-less inverters is well established.

Series arc fault detection

Series PV DC arc faults can occur when a circuit conductor is broken, or a connection is opened while current is flowing. This has been a problem with DC connectors, such as when they are not securely mated. Other potential series arc sources include manufacturing defects, improper installation, environmental stresses, and pairing different manufacturer’s connectors, known as mismatching.

Arc fault detection for PV DC ground circuits operating at 80V DC or greater first appeared in the 2011 edition of the NEC. The original listing process for DC arc fault interrupters UL 1699B, was published as an outline of investigation in 2011, but did not become a full Edition 1 standard until 2018. The full standard updated testing methodology to improve the performance and reliability of devices successfully achieving this listing.

The arc fault requirements that were added in section 690.11 required detection and interruption of a series arc. Once detected, the series arc should be extinguished by stopping all current flow in that circuit. Opening a PV DC circuit connection is a function that is straightforward for an inverter to perform. It’s possible for the inverter to provide all the functionality required by code (detection and interruption) internally. This can also be achieved via external devices designed and certified for PV DC arc fault detection and interruption. Correct detection of an arc, while ruling out false positives generated by things like the opening of a DC disconnect, is not an easy task. SMA was the first inverter manufacturer to achieve listing to UL 1699B in 2012 and, along with other manufacturers in the industry, has updated and improved the performance of devices carrying out this critical safety feature in the decade since.

Key Take Away: Code has required arc fault protection for more than ten years, and UL testing standards have been updated to greatly improve the performance of listed devices.

Rapid shutdown

Starting in 2014, the NEC included section 690.12 for rapid shutdown of PV systems. The rapid shutdown requirement was designed to reduce the potential for firefighters working near a PV system to be shocked by energized wiring that may be concealed from them.

Originally, conductors outside a 10-foot boundary of a PV array, or penetrating a building of 5 feet or more, were required to reduce voltage (to 30V or less) and power within 10 (later 30) seconds of the initiation of rapid shutdown. Equipment performing this task only had to be listed, but not listed to a rapid shutdown standard.

The 2017 NEC greatly expanded section 690.12. The biggest modification was the addition of rapid shutdown requirements internal to the array boundary (reduced to one foot around the array). Three options for compliance are allowed, use of any one of which fully satisfies the requirement.

The first option was to have the array certified as a rapid shutdown PV array. This required a safety standard that had not been written. In the 2020 NEC, this first option was revised to require a certified PV hazard control system and an informational note referred to UL 3741 PV Hazard Control. This standard was published in December of 2020, almost four full years after this “option” for compliance was introduced into code.

The second option required conductors within the array boundary to be limited to 80V DC or less within 30 seconds. Compliance under this option required inserting module level electronics (MLE) underneath each module, such as DC/DC optimizers or microinverters. Unlike the first option, devices applicable to a PV system allowing compliance under this option were available at the publishing of the 2017 NEC, resulting in the de facto requirement of module level electronics to comply with 2017 NEC 690.12(B)(2).

The third option was added to consider building integrated PV (BIPV) or other systems that would not have any exposed wiring methods or conductive parts and be installed more than 8 feet from any grounded conductive parts.

Since the publication of UL 3741, there have been several manufacturers (system integrators and racking suppliers) that have obtained a UL 3741 certification. UL 3741 allows for different methods of PV hazard control and defines the evaluation required to determine acceptable risk levels of PV arrays using these methods.

Compliance with UL 3741 can be obtained by using specific levels of physical and or fault protection to remove the need for inserting any electronic devices in the DC string, or through the use of module level electronics or string voltage limiters.

Using protection methods (such as better wire routing and securing to keep wiring from faulting to frames or racking) without requiring the use of electronic devices has the added benefit of reducing ground fault risk and reducing the number of DC connectors. The concern of arcs caused from mismatched connectors resulted in the 2020 NEC adding in 690.33(C) the requirement that mating connectors either be identical type and brand or listed and identified for intermatability. Reducing the complexity of the PV system will increase the reliability, reduce injury risk and decrease likelihood of fire.

Key Take Away: Rapid shutdown requirements are not changing rapidly in the NEC. However, many more options for compliance are becoming commercially available with the publication of UL 3741.

There is a noticeable lag between when code requires changes and when testing and listing standards are established to ensure commercial devices can provide that safety feature. In the final article of this series, we will discuss an area of code that is newer and changing very rapidly – requirements for energy storage systems.

Mike Mahon is a senior technical training specialist with the SMA Solar Academy, delivering in-person training and webinars covering all SMA America PV and battery string inverters, communications products and software platforms.

Steve Wurmlinger is the Manager of US Norms and Standards at SMA with the responsibility of representing SMA on various industry discussions and direct involvement in developing requirements for: US codes, UL safety standards, IEEE technical standards and utility interconnection requirements for inverters, plant controllers and energy storage systems.

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While NEM 3.0 is expected is to slash the rate paid for solar energy sold back to the grid, batteries can help maintain the value of solar. The next wave of clean technology adoption, however, must seek non-lithium batteries and take advantage of new safe and affordable chemistries.

California’s net energy metering (NEM) policy has been a key driver of the state’s solar deployment, incentivizing adoption by allowing utility customers to sell excess power generated from rooftop solar back to the grid for a profit. With approximately 1.5 million homes and businesses participating, policies like this have made California a clean energy leader in the United States, and even the world. However, the California Public Utilities Commission recently changed the solar-friendly policy.

The approved new framework (known as NEM 3.0) is expected to slash the rate paid for solar energy sold back to the grid by 75%. This revision significantly lengthens the five- to seven-year average payoff period for installing solar and puts the growth of solar power at risk. Californians must embrace an additional clean energy technology in order to shorten payoff periods and continue the momentum behind solar: batteries.

Under the new NEM 3.0 rate structure, the value of excess solar generated during the day is diminished. But, there is a strategically designed loophole – homeowners and businesses can maintain the value of solar power generated by incorporating a battery into their system. The battery can store excess energy for later use, including hours of the day when energy demand and prices are at their highest.

This new structure will benefit the California power grid by reducing dependence on fossil fuels during peak demand periods. As a state that commonly experiences electricity supply shortages and rolling blackouts, California has the opportunity to mitigate these issues by leveraging batteries and renewables as distributed energy resources. Further, battery systems will enable California businesses to accelerate their paths to decarbonization, which regulation will mandate in the coming years.

As demand for solar-plus-storage grows, lithium-ion battery manufacturers are racing to keep pace. However, despite the urgent need for storage as electricity prices skyrocket and grid reliability nosedives, many home and business owners remain hesitant. Lithium-ion batteries have their own risks, including rising costs and fire hazards.

In 2022, the average lithium-ion battery pack price reversed its downward trend and rose 7% to $151/kWh. As of 2021, first costs (including cost of all hardware and cost of full installation) for a 10 kWh to 14 kWh residential battery system were in the range of $10,000 to $15,000 before state-specific incentives, which is cost prohibitive for the average homeowner. Lithium is also an inherently flammable material that can make batteries a liability rather than an asset.

Lithium battery fires burn hot and fast, and are difficult and dangerous to extinguish. Burning batteries also release a range of toxic gasses harmful to humans and the environment. While it’s true California needs battery storage, it will require innovation beyond lithium for mass adoption to meet the scale needed.

The next wave of clean technology adoption must take advantage of batteries that are inherently safe and affordable. Non-lithium energy storage alternatives exist, and many more are currently being developed. These new battery technologies can help California ensure that NEM 3.0 has no adverse effects on the clean energy transition, and instead kick it into high gear.

Once deployed at scale, these new battery chemistries will serve as invaluable assets to help shape the clean and resilient power grid of the future. Much like solar panels once were under previous NEM policy, batteries will respond to and be rewarded for giving energy back to the grid when it’s most needed.

Mukesh Chatter Image: Alsym Energy, Inc.

Mukesh Chatter is the president, CEO and co-founder of Alsym Energy, a battery technology company developing high-performance, low-cost batteries to enable a zero-carbon electrified future for all. He is a successful serial entrepreneur with a track record of developing advanced technology products and leading startups from launch to success. Mukesh co-founded Nexabit Networks, a terabit switch/router company, and led the company as CEO until its acquisition by Lucent Technologies. After the acquisition, Mukesh served as the vice president and general manager of IP Products at Lucent. Mukesh also co-managed NeoNet Capital LLC, an investment firm focused on funding out-of-the-box, innovative ideas.

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The deployment of a vanadium flow battery at a fire station run by Native Americans illustrates the role that the energy storage technology can play in ensuring that nobody is disadvantaged by the shift away from fossil fuels.

From pv magazine global

Global development has always relied on exploiting natural resources. Coal, oil, and gas not only fueled hundreds of years of industry but formed many of the building blocks of modern society. During the past year, however, the world has once again been reminded of the inherent geopolitical and economic instability in an energy system based on fossil fuels. But as a result the transformation in the global energy landscape has significantly accelerated.

Policymakers are rapidly updating and adapting their energy strategies in light of the present challenges. Global ambitions for solar and wind power deployment, alongside grid-scale energy storage, are rising as countries look to lock in their long-term energy security and restrain record high energy prices, all while achieving critical decarbonization goals.

To achieve net zero, the world must deploy renewables and energy storage faster and at greater scale than has ever been seen before. This cannot be a case of advancement at any cost, however. The global energy transition presents us with a vital opportunity to reshape our societies in a more just way.

Energy for all

A just transition seeks to offer the benefits of clean energy to all, with no one left behind. A low-carbon energy system, underpinned by renewables generation and grid-scale batteries – and supported by appropriate policy and investment decisions – will lead to lower long term energy prices, cleaner air, and a huge reduction in greenhouse gas emissions. Done right, this new energy system will create tremendous economic growth and employment opportunities, with those benefits accessible to individuals whose livelihood it threatens, such as workers in the fossil fuel industry, and to communities which disproportionately bear the brunt of the climate crisis.

Invinity recently delivered a vanadium flow battery to a fire station run by the Soboba Band, or tribe, of Luiseño Native Americans in Southern California.

The battery will be coupled with solar panels, and will store excess energy produced at times of low demand to release it when the power is most valuable. The system will also provide back-up when power outages caused by wildfires hamper the ability to provide emergency services to the local community.

Beyond lithium

Energy storage systems are the key to enabling a fully renewables-powered future. By offering a solution to the inherent intermittency of wind and solar power generation, energy storage delivers low-cost, low-carbon energy on-demand for families, businesses, and grid operators around the world.

Lithium-ion batteries have dominated the market to date. Designed primarily to correct occasional deviations in network frequency and fill short-term supply gaps, the technology has done an excellent job, so far, of proving the value batteries can provide as part of our electricity system.

Yet lithium batteries have inherent challenges when used in this manner, limiting the role they can play in a just transition. Currently only 5% recyclable, lithium-ion batteries are expected to generate two million metric tons of waste by 2030. There are also a host of issues surrounding the lithium-ion supply chain, including the use of “conflict minerals” such as cobalt.

To shift to a more sustainable economy that incorporates just transition principles we must look beyond lithium as a “one-size-fits-all” option, and look to a more diverse group of battery technologies to store and deliver clean power on demand.

All of the above

Vanadium flow batteries (VFBs) are already established as a leading alternative to lithium-ion devices for stationary energy storage projects. A type of long duration energy storage (LDES) capable of providing from two to more than 10 hours of energy on demand, VFBs are gaining significant attention for their unparalleled ability to store and deliver power on an industrial scale. VFBs do this using vanadium, a metal produced around the world and used primarily to harden steel.

Unlike lithium-ion batteries, VFBs are highly recyclable and do not degrade with use, lasting 25 years or more even with heavy daily use. Vanadium is readily available and can be either mined or recovered from industrial waste. VFBs are also a safe choice as they are fundamentally non-flammable.

Invinity has already deployed VFBs at more than 50 sites across the world, and the installed capacity of its batteries is set to more than double this year in response to growing demand for the technology as its capabilities are proven over and over again in global renewable power and standalone battery projects.

Let’s act now

The increasing global deployment of renewables and energy storage technology, supported by significant policy intervention and investment in the UK, EU, North America, and Australia in recent years, is certainly cause for celebration. But we must keep just transition principles at the front of our mind as we drive towards a low-carbon future.

By broadening policy – both globally and at a national level – which supports the deployment of a diverse set of cost effective and sustainable energy storage solutions, we can avoid a path to a dependency which, left unchecked, could massively curtail the long-term benefits of the sustainable energy transition and threaten the ultimate goal of reaching net-zero with no one left behind.

Matt Harper is the co-founder and chief commercial office of UK-based vanadium-flow battery supplier Invinity. His career spans pioneering work in electrical energy storage, wastewater treatment, hydrogen generation, and fuel cell vehicles. He holds a master’s degree in management and engineering from MIT.

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As the U.S. Uyghur Forced Labor Prevention Act demonstrated, companies preparing to spend big on batteries are at risk of being blindsided by supply-chain-related legislation. Here are some tips on how US developers can anticipate policy curveballs.

From pv magazine global

Lithium-ion batteries can store energy from intermittent sources such as solar and wind generation, adding critical flexibility to the increasingly dynamic electric grid. But as the storage industry’s future brightens with new freestanding tax credits brought in by the Inflation Reduction Act, so does the spotlight on global battery supply chains.

The PV industry’s experience presents a cautionary tale: A recent report from the Solar Energy Industries Association found tightening trade regulations, designed to address labor concerns in the PV supply chain, contributed to a 23% decline in U.S. solar installations last year compared with 2021.

Policy shifts

An industry can adapt to such shifting policies, but this takes time, especially with so many moving parts. Anticipating and preparing for the future policy landscape, in tandem with the environmental, social, and corporate governance requirements of end customers, will be critical in realizing the storage industry’s full potential.

While trade policies in the solar supply chain center around a single element – silicon – navigating the upstream lithium-ion battery supply chain is an order of magnitude more complicated. In North America, electric vehicle batteries typically use nickel-manganese-cobalt (NMC) chemistry, whereas stationary storage applications commonly use the less energy-dense lithium iron phosphate (LFP) chemistry.

Both NMC and LFP cells consist of many sub-components, such as the cathode, anode, and electrolyte, each of which have their own extensive material supply chains. Critical materials such as graphite, lithium carbonate, copper, and aluminum all require various levels of mining and processing and may pass through multiple countries before winding up in a utility scale storage facility or electric vehicle. Given that complexity, what can buyers do to prepare for greater scrutiny of their supply chain and to pre-emptively improve accountability?

Code of conduct

Potential regulation and growing consumer consciousness are putting increasing responsibility on battery sellers and buyers to build transparency into how, and with whom, they do business. The first step as a buyer is to clearly define corporate social responsibility policies by developing a code of conduct. This should set clear standards for topics such as labor practices, stakeholder engagement, and environmental impact mitigation. An equivalent code of conduct should also be developed for suppliers. By codifying values and company mission upfront, the appropriate tone for conversations with suppliers can be set.

Businesses without a corporate responsibility program to inform the drafting of codes of conduct should create one. This ensures their approved vendor list is limited to suppliers who align with their organization’s values. Two good resources for this are the ISO 26000 guidance on social responsibility, and the guidebook on responsible sourcing drawn up in 2021 by trade body the US Energy Storage Association.

Once a code of conduct is developed, appropriate language should be incorporated into supply agreements. The terms of supply deals should ensure that the code of conduct is applied to the supplier as well as to its entire supply chain, for all components. The language used must be binding and provide clear remedies if sub-suppliers are not compliant. Additional language, ensuring cooperation on other supply-chain related requests – such as facilities access and supply chain mapping – should also be included.

Supply chain mapping

The mapping of a battery supply chain is critical to identify potential risks, as tracing materials to the mine level clearly identifies all participating suppliers. This level of visibility enables buyers to determine which sub-suppliers may bear greater risk of non-compliance with their code of conduct.

The complexity of the battery supply chain and potential resistance of sub-suppliers to sharing this information makes mapping challenging. To ease identification, it will be helpful to initially focus on sub-components which bear more risk or have limited areas of production, and to pay less attention to those materials that are manufactured globally in great quantities, for example copper and aluminum.

Importance of audits

After negotiating for more transparency and access, and mapping the supply chain, it is important to verify that suppliers are indeed compliant with their contractual obligations. On-site processes and supplier qualification procedures should be reviewed and validated to ensure that the buyer’s code of conduct is being implemented in practice, rather than only on paper.

Before sourcing becomes even more complicated, there is a golden opportunity right now to incorporate more accountability into battery supply chains. Taking proactive measures to align purchasing with company values will pay dividends when new policies inevitably take shape.

This may present unique challenges depending on the size of businesses. A smaller company may have a harder time shifting its suppliers’ practices than a larger one. Ideally, coordination on uniform practices will ultimately utilize the industry’s collective bargaining power to push suppliers towards more transparency. The straightforward steps outlined above, meanwhile, can build resiliency to potential policy changes and meet consumer demand for responsible products.

About the authors: Raiene Santana is an associate engineer with CEA. Santana has six years of experience in the solar industry, and supports CEA clients on supply chain traceability and ESG. She previously held roles in energy engineering and international affairs at ENG3 and Solar Energy Industries Association (SEIA), respectively. She holds a master’s degree in energy efficiency from the Federal University of Espirito Santo.

Andreas Savva is an applications engineer, energy storage, with CEA. Savva has five years of experience in battery research and development, including extensive experience with lithium-ion and alkaline zinc battery chemistries. He holds an MS in materials science and engineering from Boise State University and a BS in chemical engineering from NJIT.

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The Inflation Reduction Act of 2022 is not an eat-all-you-can feast for developers.

In this article we look beyond the headlines of the Inflation Reduction Act and at some of its pitfalls and direct opportunities for solar developers. Apricum is best known in Europe and the Middle East, but the US represented 25% of group revenues last year. Our development clients eyeing the US should be mindful of the complexity in capturing these IRA-led opportunities. Solar development is not an all-you-can-eat feast; familiar challenges mean only a few strategies are likely to yield immediate results when trying to capitalize on these opportunities.

The IRA has tilted the renewables industries on their axis. Many clients now debate the merits of US expansion: 10 years of policy certainty, with higher asset values, ends the inefficient policy lapse and extension cycle to allow developers, investors and other stakeholders to make longer term plans.

However, just like in Europe, supply chain constraints, long interconnection queues, and rising interest rates all create challenges to building successful projects and add uncertainty. Capturing the opportunities will require greater strategic insight than in other booming markets.

Fig. 1: U.S. solar installation forecast by segment Source: Apricum PV market model center scenario 2Q2022

• Interconnection queues drive project timelines in the US and are the leading cause of project failure in most markets. These processes and issues are very different across the spectrum of vertically-integrated utilities, Regional Transmission Organizations and Independent System Operators (RTO’s/ISO’s) that lay across the US in patchwork fashion. Some ingenious and nimble strategies can be deployed by astute developers to circumvent the resulting project delays that otherwise occur from sticking with the standard utility-scale development template. Picking sub-markets and selective strategies are critical to success. For example, projects connecting at distribution voltage below 69kV can go through local interconnection processes more quickly because they are subject to state rather than federal regulation. In markets such as Virginia, PPAs can be secured with both corporate buyers or large utilities like Dominion Energy, allowing developers to complete the ISO processes in PJM at a later date to provide additional offtake options.
• Certain IRA financial incentives subject projects to stringent local content requirements. In order to qualify for an additional 10% tax credit, local content must constitute 40% of the project if starting construction before 2025, rising by 5% per year to 55% for projects starting construction in 2028. Companies eyeing tax incentives can face bureaucratic hurdles, without in-house/external expertise that understands these supply chain implications.
• The IRA simplifies tax credit transferability between taxpayers, reducing the need for complex partnership flip structures and five-year hold periods. Projects can be designed for RTB or COD sale in a more straight-forward manner.

While the IRA has national application, this does not diminish the need for local market sensitivity. Some stackable IRA incentives will also only apply to local communities (ie:+10% for low-income or fossil fuel dominant communities). But the largest impact is from local energy market design and policies. Below we review the top four below with a developers’ eye.

• ERCOT

The majority of the Texas population is served by ERCOT, an independent grid insulated from the rest of the country. Within ERCOT, which is not subject to federal regulation, developers generally have more flexibility in deploying infrastructure. The Lone Star state has a geographically zonal market structure, presenting very different opportunities for projects. Historically dominated by wind, in recent years solar and battery storage have grown rapidly. Unique characteristics such as a lack of capacity market, a highly open and competitive retail energy market, and the ability to build private-use networks, mean projects in Texas have unique requirements. For instance, many projects are financed using hedges instead of a PPA, or a PPA only for a portion of the total capacity, running the additional capacity as merchant power to capture spot market pricing that can be as high as $5,000/MWh during periods of high demand.

• PJM

PJM is the largest system operator in the US. It is part of the Eastern Interconnection grid operating an electric transmission system serving all or parts of Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia, and the District of Columbia. Most large projects in PJM were given two year delays in mid-2022 while a new interconnection process was implemented. This pushed almost half of projects in development out to the 2025-26 timeframe. The result is an opportunity for patient capital, such as new market entrants from Europe, to cheaply acquire partially-developed projects whose domestic appeal has diminished with the later connection dates. Additional opportunities exist for projects connected at the distribution level with utilities in specific state markets. PJM projects in particular benefit from sourcing short-term PPA’s with local utilities prior to broader market access.

• CAISO

Historically one of the largest and most active markets for solar in the world, recent years have seen extraordinary growth of renewable projects paired with storage in California. The rise of Community Choice Aggregators is challenging the status of the big three in-state regulated utilities [PG&E/SoCalEdison/San Diego Gas & Electric] and creating opportunities for new contracts/customers. This is not as easy a market as new entrants assume. Challenges around credit and structuring exist with CCAs, and it’s never easy to surmount permitting obstacles for new projects of any type anywhere in California.

• NYISO

Like California and Texas, New York has its own single-state system operator, making project development somewhat more straightforward. Like California, New York has strong renewables and energy storage ambitions in pursuit of aggressive decarbonization targets. Unlike the other states, opportunities for the largest solar developers are limited: insolation quality is mediocre, and there are few sizable parcels of land suitable for large-scale PV deployment. However, community solar and behind-the-meter markets are fairly robust, spurred by leading distributed energy resources (DER) pricing policies. Moreover, given New York’s plans to add 9 GW of offshore wind by 2035, as well as significant intrastate transmission bottlenecks constraining the ability to serve New York City, the need and value associated with energy storage assets is profound.

Jesse Atkinson is senior advisor and country representative USA, for Apricum Group. He is the former president of Cratus Energy and board member of Alion Energy.

Richard Stuebi is senior advisor for Apricum Group. He was also founder and president, Future Energy Advisors; former board member ESA; former VP, US strategy & group technology, National Grid; managing director, Early Stage Partners.

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CEP Renewables installs nearly 60,000 solar panels on former municipal landfill, transitioning previously unusable land into revenue-generating, clean energy asset.

There are over 10,000 closed landfills in the United States, and it has been determined that closed landfills could host more than 60 GW of solar capacity – enough to power 7.8 million homes, according to a 2021 study by RMI, and this figure is rapidly increasing with the growing number of landfill projects in the past two years. CEP Renewables, for example, currently has 16 landfill or brownfield solar projects under development, and the company reports that its most recently completed 25.6 MW Mount Olive, project is the largest landfill solar project in North America.

CEP was selected by the Township of Mount Olive, New Jersey to redevelop the former Combe Fill North Landfill Superfund site into a revenue generating, solar energy asset. The landfill had been operating as a municipal sanitary landfill for fifteen years. In the early 1980s the owner went bankrupt, the property was abandoned and the landfill closed.

Like many former landfills, the property was listed on the United States Environmental Protection Agency’s (EPA) National Priorities List of Superfund sites. Due to its improper closure, runoff from the landfill was draining into local creeks and contaminating groundwater that nearly 10,000 community members depended on.

The town was also losing tax revenue, as $2.3 million was still owed in back taxes on the abandoned land. Most commercial developers also did not want to purchase the property because environmental restrictions and New Jersey environmental requirements meant that no commercial uses could be built on the sensitive, capped landfill without risking piercing the landfill’s protective seal. The New Jersey Department of Environmental Protection (NJDEP) eventually determined that it would only allow a solar facility to be built on this former landfill site and the Township adopted a redevelopment plan permitting a solar array.

Public-private partnership

CEP’s team of landfill and brownfield experts negotiated a unique public-private partnership with the Township and NJDEP that allowed CEP to purchase the landfill by way of the redevelopment and tax lien foreclosure process. As part of the agreement, CEP agreed to pay the back taxes to the Township over time in addition to redeveloping the land into a tax revenue-producing solar field.

The deal also involved an administrative consent order between the NJDEP and CEP that stated that in exchange for CEP agreeing to redevelop the land and take over long-term maintenance of the cap, the State of New Jersey would assume all liability for air pollution and water contamination associated with the site.

The solar installation includes approximately 57,000 450 W Boviet solar modules with a Toshiba Mitsubishi Electric Industrial Systems (TMEIS) inverter. The project won the 2021 Award for Innovation in Governance from the New Jersey League of Municipalities, and it now serves as a financial and legal model for the myriad other closed landfill sites throughout the U.S. to follow.

“Only a small fraction of the 10,000 closed landfills across the U.S. have been converted into solar fields. The unique structure we used to implement this project now serves as a model that can be leveraged to redevelop more closed landfills into revenue producing assets that facilitate cleaner air, tax revenue, jobs, and more affordable energy for residents,” said Chris Ichter, executive vice president at CEP Renewables

Landfill settlement analysis

Landfill settlement analysis is critical in order to ensure that the design and construction preparation is adequate for installing the solar array atop the landfill, while avoiding damage to its protective layer. The stability and slopes of various sections of the landfill need to be determined through this analysis, which will then help with specifying where the best locations to enable site access are, given that there will be obstructions that need to be considered.

Mount Olive solar. Image: CEP Renewables

CS Energy completed a thorough landfill settlement analysis on this site prior to designing and engineering the solar installation and developing the site access plans. The company was able to use its experience on over 200 MW of landfill solar projects to conduct this analysis, which included the use of ground penetration radar, to determine landfill weight requirements and the safest access points. CS Energy planned out the cable tray locations to ensure access in and out of each of these key areas, which is crucial not only for the installation of the solar system, but also for ongoing operations and maintenance work in the long term.

Based on this analysis, CS Energy used only tracked equipment and, where required, low ground bearing pressure machines. Ultimately, CS Energy was able to design and build this project on time and on budget, without affecting the landfill cap, as a result of its significant preparation work and extremely cautious construction at each stage of the project’s design and construction.

Value engineering

Being the largest landfill solar project in North America, every slight increase in product cost is multiplied and compounded across the entirety of this immense project. Terrasmart, the racking and mounting provider, had seen concrete costs rising, which affected the cost of its ballast blocks. This presented a challenge, as mounting solution companies need to be able to minimize the tilt of the solar array in order to reduce the amount and size of blocks needed, while still ensuring high energy yields from the solar array.

Additionally, in cold climate locations, the solar array tilt cannot be so low that an inordinate amount of snow is able to pile up and cause a great deal of stress on the racking system. This is particularly important for projects like the Mount Olive project, which are located on top of a sensitive landfill cap that cannot be pierced.

The GLIDE solution

Leveraging its experience on several other large-scale landfill solar projects in cold weather locations, Terrasmart was able to successfully design and engineer their GLIDE ballasted mounting solution for this project such that the cost of the blocks was reduced by 50 percent. From wind studies to countless solar generation analyses, Terrasmart determined the optimal tilt and block size to help CEP meet its project budget and energy production goals – all while protecting the sensitive landfill cap.

With over 20 GW of solar deployed across 4,800 solar systems, including its legacy business RBI Solar’s decades of experience in solar landfill development, the new Terrasmart has become the leading provider of solar racking technologies that provide solutions for projects located on all types of terrain.

Landfill solar projects often require fixed-tilt, ballasted mounting solutions that do not pose a risk of piercing or otherwise damaging the landfill cap, which could result in the spread of hazardous contaminants. In order to ensure the myriad integration and delivery deadlines for the skid mount system are met, close collaboration with project partners is paramount.

Having completed over 4,000 skids, Lindsay Precast was able to leverage its steel skid manufacturing and integration capabilities, including on many landfill solar projects. Lindsay Precast’s deep understanding of the entire value chain of a solar project and ability to efficiently provide quotes and accurate schedule estimates made this challenging project as streamlined as possible.

Precast has also completed countless projects with Terrasmart and this project marks the company’s seventh project with CS Energy, which includes the award-winning Cuyahoga landfill solar project. The decades of experience Lindsay Precast has spent working with these partners enabled the skid mounting solutions for this project to be seamlessly integrated and delivered on time and within budget.

Benefits and long-term impact

As a result of CEP, CS Energy, Terrasmart and Lindsay Precast’s extensive landfill solar project experience and collaboration, the Township of Mount Olive was able to not only recoup approximately $2.3 million in back taxes but will also now benefit from future taxes that this property will provide. The electricity generated by the array is enough to power over 4,000 homes.

The 25.6 MW dc of solar electric power contributes to the State of New Jersey’s aggressive renewable energy production goals. After 40 years, the property now has a long-term owner – CEP Renewables – that will be responsible for maintaining the landfill cap for the duration of the life of the facility. The Mount Olive project now serves as a model for the plethora of other closed landfill sites throughout the United States, both in terms of the redevelopment process as well as the design and construction execution, while providing cleaner air and more affordable clean energy for local communities.

CEP is currently under development on at least 16 other landfill or brownfield redevelopment projects in New Jersey. However, without a dramatic change in the state’s policy and attitude toward these projects, creating more successes like Mount Olive will prove difficult, if not impossible.

These projects are all certified by the New Jersey Board of Public Utilities (NJBPU) under what is known as the subsection “t” certification process. Subsection “t” is a subsection of the Solar Act of 2012 that provides a regulatory framework by which landfill and brownfield redevelopment projects receive state incentives. Once certified under subsection “t,” a project has two years to complete commercial energization. That timeframe is currently impossible due to a multi-year interconnection moratorium announced in April 2022 by PJM Interconnection, LLC, the regional interconnection organization that monitors New Jersey’s and other states’ electrical grids.

Due to the PJM delays, most of CEP’s projects will not be eligible for interconnection until 2027 or 2028 at the earliest.

Although the NJBPU is aware of this, the most the Board has been willing to do is extend the 2-year construction period by up to one 12-month extension – which is not nearly enough time based on PJM’s published information regarding the delays and PJM’s interconnection reform process, which was just recently approved by the Federal Energy Regulatory Commission.

CEP has petitioned the Board to reconsider the 12-month extension to provide sufficient time to allow these important and transformative projects to interconnect to the regional grid. Unless the state and the Board get behind these projects and allow them the time necessary to proceed, it is unlikely that the state will see more successes like Mount Olive.

CEP remains optimistic that the Mount Olive project can be replicated on additional closed landfills throughout the state with the support of the state and NJBPU, as landfill redevelopment solar projects are necessary to mitigate climate change and provide precious funds, cleaner air and more affordable clean energy to local communities, particularly those that have been burdened by these economically and environmentally destructive properties for decades.

Lisa DeMarco, communications director at TwentyTwo & Brand.

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The solar module buying journey is anything but predictable.

In a volatile, supply-constrained environment, pricing and availability can change in an instant, sending buyers right back to the starting point. Ask a large energy buyer how to manage the solar procurement timeline, and the answer might go something like this: “Recently, if panels are available, we and our competitors are buying them within hours of hearing about the availability.”

The “buy first, ask questions later” strategy carries some risk. But so does almost every approach to solar procurement. Each step can take the buyer closer to a supply agreement that in turn leads to project profitability or deals a frustrating setback.

Experienced module buyers probably know the steps to take and the considerations to make, but as the graphic below suggests, procurement can sometimes feel like the children’s game, Chutes and Ladders. Even the most seasoned players can benefit from a refresh of the best practices and guiding strategies needed to navigate the ever-changing procurement process.

There are three key areas that impact a buyer’s success: visibility into the supply chain, buying power, and module value analysis. This article reviews the most important questions to ask at each step along the way.

How to play the procurement game

Data collection is the first step in the procurement process. Large-volume module buyers need to know which modules are available for purchase in line with their budgets and the timing for project development. They also need answers to questions such as:

• What are the electrical and mechanical characteristics of these modules?
• What are the purchasing terms and conditions?

There might be a procurement team responsible for data collection, or that work might be delegated to someone who has various responsibilities. Either way, most buyers have to contend with limited access to supplier data and poor data quality once their information is no longer up to date.

With a valid set of module data in hand, one can move to step two — data analysis. Some of the analysis can be completed in-house, such as verifying that equipment is compatible with the rest of the project components and overall system design. Other aspects of data analysis depend on third-party input, including the following:

• Has the combination of modules and racking been used in a previous project?

If not, the module manufacturer may need to show allowable mounting options.

• Has testing been done, and if so, is a test report available? If not, this could mean sending module samples to the racking supplier or vice versa for analysis.

Wait times for responses from suppliers can vary, and it often depends on the supplier and the buyer’s relationship with the supplier.

Performance engineering, the third step in solar procurement, helps module buyers evaluate the impact that selected equipment will have on energy production. If a project is financed, as most are, the financier will want to see independent test results answering questions such as:

• How is the module affected by light-induced degradation that occurs in the first hours or days that a module is exposed to sunlight?
• How do the modules respond to variations in temperature and irradiance, as reflected in PAN files?

For each module, it can take days or weeks to get third-party reports if they exist, and then the results must be vetted until there is enough confidence to proceed with the project. This itself is a multi-step process.

Here are the steps to ensure an accurate performance model:

• Verify that the PAN file was produced based on test data from a third-party lab.
• Then review the results to ensure that the lab followed accepted testing standards and confirm that the PAN file parameters produce a good match to the test results.
• Finally, compare the PAN file to the module datasheet to make sure the parameters match.

Leveraging buying power in procurement

The end of the procurement process is nearly in sight. But timeline management continues to be unpredictable and full of risk, which undercuts buying power for the module buyer.

The next step is vendor due diligence. In this fourth step, the questions to answer include:

• Are the financing parties involved in the deal satisfied with the bankability of the modules?
• Do the financing parties believe the quality of the vendor’s production process and its risk mitigation strategies, including the manufacturer’s warranty, are sufficient?
• Are the product reliability assessments convincing enough to win approval from financiers?

It’s also important to account for legal and regulatory compliance, such as the Uyghur Forced Labor Prevention Act (UFLPA), a law enacted in 2021 to keep goods produced in the Xinjiang Uyghur Autonomous Region of China, including raw materials used in solar modules, out of the U.S. market.

Contracting, step five, might be the riskiest step of all. So many resources have been invested to reach this point. And yet, a shift in module pricing or availability could send the buyer back to the start.

Module buyers might have to wait several months before they have a negotiated and executed supply agreement. Once again, it depends on the supplier and the buyer’s relationship with the supplier. All the while, none of the procurement terms can be guaranteed until the contracts are signed.

The inherent risk at this stage can put module buyers at a disadvantage when negotiating terms with the supplier. At this point, the questions to ask are:

• How long will it take to get signatures on a purchasing contract?
• Can the cost of shipping be quantified based on the manufacturer’s proposed terms in the supply agreement?

Using module NPV to optimize project value

If the data can be synthesized from each step in the procurement process, the value of different modules can be compared and that comparison can be used to optimize overall project value. The best way to do so is to determine each module’s net present value (NPV). NPV calculates an asset’s costs and projected income and assigns a present-day value, accounting for the fact that money has greater value now than it will in the future, a concept known as the time value of money.

Consider the purchasing terms learned during data collection. Terms that reduce capital costs will generally improve NPV. The data analysis performed in step two provides insight into labor and balance of system (BOS) impacts of a given module. Simple, streamlined installation processes also boost NPV.

Now it’s time to consider module degradation during performance engineering. As a general rule, NPV is higher when module degradation is lower. Degradation also affects project O&M. Higher degradation has the effect of driving down gross revenue.

Questions to ask to evaluate overall module value include:

• How do low-price modules stack up in terms of long-term energy output and revenue?
• Are there modules that aren’t the lowest cost, in terms of dollars per watt, but create the most project NPV?
• Which factors in module procurement (i.e., timing, brand, module risk) are most important to the success of the project?
• Are you struggling to find availability to satisfy the requirements of your projects?

Procurement solutions reduce risk

It might seem easy to take a do-it-yourself approach for some steps in the procurement process for a couple of module options. But doing a deep dive into all the module options can be time consuming.

What’s more, taking the time to eliminate production model ambiguity and deliver a trustworthy model that financiers are more likely to accept can slow the time to get to the finish line. Having a reliable procurement solution means not having to risk starting the game over again if some of the checklist steps are missed, or if something goes wrong.

Aaron Hall is a solar veteran with 22 years in the industry. He is currently president of Anza, a Borrego business that is an optimized online marketplace where large-scale solar module and energy storage equipment buyers can quickly see a list of vetted, attractively priced options maximized for net present value based on project inputs.

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By unreasonably limiting Duke’s near-term procurement of clean, low-cost solar resources, the Commission’s order will increase costs for ratepayers and delay reductions in Duke’s carbon emissions.

On December 30, 2022, the North Carolina Utilities Commission issued its long-awaited order in the Duke Energy Carbon Plan proceeding. By unreasonably limiting Duke’s near-term procurement of clean, low-cost solar resources, the Commission’s order will increase costs for ratepayers and delay reductions in Duke’s carbon emissions.

Under landmark legislation passed by the North Carolina General Assembly in 2021, the Commission was required to adopt a plan for reducing Duke’s North Carolina carbon emissions by 70% (against 2005 levels) by 2030, unless the deadline is extended by the Commission under certain allowable circumstances.

Last May, Duke filed a proposed Carbon Plan. It included several portfolios for achieving the required carbon reductions, but only one that would do so by 2030. Interested parties, including renewable energy suppliers, customer groups, environmental organizations, the North Carolina Attorney General, and the state’s consumer advocate, filed thousands of pages of comments and expert testimony on Duke’s plan. Our companies were active participants throughout the proceeding through our trade association, the Clean Power Suppliers Association.

The Commission held a three-week hearing in the fall, and on December 30 issued a 137-page order directing Duke to take a suite of 39 actions to begin reducing its carbon emissions and to continue and improve the planning process going forward.

The Commission’s order deals with a wide range of complex issues. However, at its core the order seeks to establish a comprehensive plan for retiring Duke’s expensive and dirty coal plants and replacing them with cleaner alternatives. The key question in the proceeding is what that alternative resource mix should look like to achieve 70% decarbonization in the least-cost manner while maintaining or improving system reliability, as required by the legislation.

Duke and other parties presented a variety of resource “portfolios,” which included various combinations of new solar, wind, natural gas, nuclear, battery storage and hydroelectric resources. In support of their alternative portfolios, commenters produced detailed modeling, developed by nationally recognized energy consulting firms. Many of the alternative portfolios presented could have achieved quicker emissions reductions than Duke’s, and at lower cost.

The Commission appropriately concluded that it’s not necessary to settle on a single portfolio now, and instead approved a series of steps to be taken over the next two years that are intended to make reasonable progress toward achieving the goal while keeping a wide range of portfolio options on the table.

One of the most important of those steps is the procurement of new solar resources by Duke. No party disputed that solar and solar-plus-storage are the most proven, affordable, and scalable zero-carbon generation resources available to Duke’s system. It was also undisputed that the least-cost pathway for achieving compliance with the decarbonization mandate while maintaining reliability would be to maximize solar additions in combination with other resources that provide power when the sun isn’t shining.

CPSA’s expert witness documented that ratepayers could enjoy huge savings by adding substantially more solar than proposed by Duke, including $860 million of savings in 2030 alone, assuming conservative solar costs and not accounting for Inflation Reduction Act incentives. While our modeling showed the need for natural gas additions comparable to those proposed by Duke, it demonstrated that adding more solar would avoid the need to invest in more costly and uncertain zero-carbon resources like small modular nuclear reactors (SMRs). Other intervenors, including the Attorney General and its expert witnesses, reached similar conclusions.

The Commission ignored virtually all of this evidence and agreed with Duke that that it need only procure 3,100 MW of new solar through 2024. This is a bad outcome for ratepayers and for the goal of reducing Duke’s carbon emissions in a timely fashion while maintaining reliability.

Duke claimed that the solar resources it is required to procure should be limited by the rate at which it thinks it can interconnect such resources to its system. The Commission declined to require Duke to test its ability to improve its interconnection rate by procuring and trying to interconnect more solar, arguing that doing so might require Duke to pay more for solar if prices come down over time. Leaving aside the uncertainty as to whether solar prices actually decline, this argument ignores the fact that failing to include more solar in the overall resource mix means that significantly more expensive resources will have to be procured instead.

Although the Commission claims that it hasn’t given up on achieving H.B. 951’s decarbonization mandate by 2030, its refusal to require Duke to procure more solar through 2024 almost certainly makes 2030 compliance impossible. The Commission can correct this error, save ratepayers money, and expedite the required reduction in carbon emissions by adjusting the solar procurement volumes upward this year and next, by significantly increasing solar procurement volumes in the next iteration of the Carbon Plan, and by pushing Duke to investigate ways to improve its interconnection performance. We urge it to do so.

Steven Levitas and Tyler Norris are co-chairs of the Clean Power Suppliers Association. Levitas is Senior Vice-President for Regulatory and Government Affairs at Pine Gate Renewables. Norris is a Vice President of Development at Cypress Creek Renewables.

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The Inflation Reduction Act (IRA) opened a new door for solar manufacturers, as one of the executives behind a Philadelphia Solar to bring PV production to the U.S. explains.

From pv magazine global

There is no question the Inflation Reduction Act has been financially attractive for solar manufacturers, opening a door to opportunity that has never existed before.

For manufacturers, the bill contains tax incentives for domestic fabrication, including an increase in the investment tax credit available, from 30% to 40% for projects using domestic content, as well as production tax credits linked to specific products. But the real benefit is the timeframe, which extends the bill’s credits and incentives for 10 years, making manufacturing investment tenable for the first time.

Big draw

The U.S. market has always been one of the biggest that has attracted solar module suppliers. As a global manufacturer of solar modules and mounting structures, Philadelphia Solar has had its sights set on this market for years. We see the future being not just in supplying modules but in investing in the U.S. to set up domestic manufacturing capacity. We took serious steps towards this in 2020 by putting a bid on a building in Texas to set up U.S. manufacturing operations. However, we pulled back because of changes in regulation – namely the cancellation of Section 201 trade tariffs on imported bifacial solar modules. The exclusion of bifacial products from a trade tariff imposed because of the volume of imports, meant that, if we were to invest in production capacity for U.S.-made bifacial modules, we would have faced extreme pricing headwinds from imported bifacial products. In the absence of any other incentives, our return on investment would have been untenable.

As a multinational tier-1 solar module manufacturer, it would have made more sense for us to export our monocrystalline PERC (passivated emitter, rear contact) modules to the US market, rather than manufacturing them in-country. Of course, that would also have meant that the supply of bifacial panels to the U.S. market would have continued to be subject to supply-chain pressures which, even while remaining unknown, still presented a lower risk to us than the investment required to set up US manufacturing in the pre-IRA trading environment.

Policy certainty

To be clear, the only way to bring stability to the U.S. solar market is to open doors for high-quality, U.S. -made solar modules, particularly monocrystalline bifacial modules, which are widely seen as essential for utility scale solar development. The lessons of the past few years have taught the world that energy independence must be based on viable local sources. Currently, the U.S. solar market is dominated by outside manufacturers, including those accused of price dumping. While efforts have been made to curtail unfair trade practices, U.S. trade regulations are imposed for two years before they are reviewed. A judge can stop these at any time, making the long-term investment necessary to set up viable manufacturing facilities too risky. Investment in U.S. manufacturing, by companies like ours, is critical to bringing true energy independence to the U.S. and it requires a much longer investment period than the usual regulatory cycles allow.

The IRA dramatically changed all this. The 10-year timeline for the bill’s provisions has brought us clarity over an extended period for the first time. Now we can move forward with confidence in implementing a two-pronged strategy that aligns perfectly with the U.S. market and its solar ambitions.

Through a joint-venture with U.S.-based Translucent Energy, we can immediately offer competitively-priced, high-quality bifacial and black modules made in our Middle East facility, to meet the current market demands for these panels. At the same time, by moving forward on our plans to set up domestic manufacturing under the Philadelphia Solar USA brand name, we are on track to supply U.S.-made monocrystalline PERC units by 2024 at a better price point. We also are actively transitioning all our manufacturing facilities to heterojunction (HJT) solar manufacturing, so we will be able to bring higher-efficiency domestic modules at increasingly lower price points by 2025.

In the long run, we are hoping for more than just the IRA. Of the 11 raw materials we need to build a panel in the U.S., seven need to be imported and all of these are currently subject to tariffs.

The IRA’s tax credits and other incentives are attractive enough to offset such trade measures but it’s critical to understand that almost half of the cash we will receive back through the IRA will go to pay customs duties on raw materials. With the remaining 50% of tax-related cashback, we will still be profitable producing a U.S.-made panel that can compete with bifacial imports that continue to be excluded from Section 201 tariffs. The margins are slim, however.

As domestic U.S. production accelerates, there is a reasonable expectation that the bifacial exception from 201 tariffs will not be extended past its current term. Reimposing such duties would bring greater profitability to U.S.-based manufacturers in the near future. This is essential. While we are excited to be playing an active role in bringing a clean and independent energy future to the U.S. we, like all the manufacturers involved, must also be profitable if that future is to be sustainable.

Mohammad Shehadeh, chief commercial officer at Philadelphia Solar. Image: Philadelphia Solar

About the author: Mohammad Shehadeh is chief commercial officer for Jordanian solar panel and mounting structure manufacturer Philadelphia Solar, which has formed a joint venture with US module manufacturing new entrant Translucent Energy to develop solar production capacity in the United States.

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By raising the visibility of role models for women in clean energy, the C3E Initiative is helping to attract more women to the field. Read about this year's winners of the C3E Awards.

The C3E Awards recognize mid-career women who have demonstrated outstanding leadership and accomplishments in clean energy. Now in its 11th year, the C3E Initiative is led by the U.S. Department of Energy, in collaboration with the MIT Energy Initiative, Stanford University’s Precourt Institute for Energy, and the Texas A&M Energy Institute.

By raising the visibility of role models for women in clean energy, the C3E Initiative is helping to attract more women to the field—catalyzing innovation, fostering new business models, and expediting global progress toward a clean energy economy. This year’s winners are working in diverse clean energy fields and are illustrative of a group of women who are accomplished inventors, researchers, as well as leaders in business, community engagement, government, and international development.

Sarah Bieber, director of energy partnerships at Acumen, works to bring power to the 730 million people living without access to electricity today. During the COVID-19 pandemic, she convened early working groups and raised a $90 million relief fund to ensure that supply chain challenges didn’t undermine clean energy projects that serve low-income customers in Africa and South Asia. In her work at Acumen, she continues to invest in emerging clean energy businesses committed to serving the poor.

Angelica Ramdhari’s first foray into renewable energy came at the University of Florida in Gainesville where she assisted the University’s athletic program become carbon neutral. The Neutral Gator program utilized energy-efficiency investments in affordable housing to create carbon offsets for campus sporting-event facilities’ emissions. After graduation, Ramdhari returned home to New York City and joined Solar One, a leading green-energy nonprofit. She is director of the Resilient Solar program which focuses on the design and collaborative installation of solar and battery resilience projects in low-income coastal communities in Brooklyn and the Bronx. The projects provide clean energy, emergency-blackout power, and affordable battery systems to public schools and libraries in those neighborhoods at high-risk of extreme storm flooding.

Shirley Meng often refers to herself as a ‘battery doctor,’ and she is applying her theoretical training to discover better, longer-lasting energy storage that can last decades. Efficient, reliable energy storage is critical for wind and solar projects, and Meng is working across several institutions including the Pritzker School of Molecular Engineering at University of Chicago, the Argonne Collaborative Center for Energy Storage Science (ACCESS), and the Laboratory for Energy Storage and Conversion (LESC) at the University of California San Diego to investigate new, scientifically-sound batteries. One of her discoveries was commercialized by a new company, South 8 Technologies.

Phoebe Wang realized early in her career that bringing clean energy technology would require business training to supplement her materials engineering degree. After earning an MBA from Rice University, she leveraged her scientific and business training to launch a career as a cleantech venture capitalist. Today, she serves as an investment partner at the Amazon Climate Pledge Fund and has invested more than $150 million in frontier technology startups during her 10-year tenure as a venture capital investor. One of her investments was in South 8 Technologies, an energy storage start-up utilizing fellow 2022 C3E winner Y. Shirley Meng’s research.

Sylvia Louie currently serves as the Director of Business Development of New York Power Authority (NYPA). She is responsible for ensuring NYPA meets the ambitious climate change goals adopted in New York State. Leveraging her bachelor’s degree in mechanical engineering and her years of leadership within the organization, she is working across the agency to develop of large-scale renewables, energy storage, and transmission projects to help meet new clean energy standards. She is a licensed professional engineer (PE) in the state of New York, as well as a certified project management professional (PMP).

Based at the Idaho National Laboratory, Rachel Taow is a process modernization lead at the Gateway for Accelerated Innovation in Nuclear (GAIN). Her work helps modernize public-private partnerships to advance a new generation of nuclear power investments. Like many in the C3E cohort, she was encouraged to pursue additional training – in Taow’s case a law degree – to deepen her knowledge and achieve her future career goals.

Ramsay Siegal always wanted to be an architect. Like many of the C3E cohort, she realized that understanding how a building was constructed was only part of the solution to addressing larger global challenges and she focused on the emerging green building field. Siegal pivoted to working on projects that integrated solar technology, and eventually moved into climate tech venture capitalism. Today, she works with Earthshot Ventures to leverage their funds to support entrepreneurs addressing climate change.

Shannon Miller is the chief executive officer and founder of Mainspring Energy, where she leads the design, manufacture, and commercialization of the Mainspring Linear Generator. Firming the grid is critical to ensuring solar and wind technologies are part of clean energy power infrastructure. The Mainspring Linear Generator is a prime example of the innovation needed to improve the reliability of clean energy networks. Miller has embraced the role of co-inventor and business leader, and established core values that promote pragmatic optimism, excellence without ego, and proactive collaboration.

One of the goals of C3E is to continue to inspire and support women as they pursue their careers. These women are leaders within their fields, and many also mentor and support other women in the clean energy sector. Do you know a mid-career woman who has done exceptional work in the clean energy space? We want to hear from you! C3E nominations are open through February 15.

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The U.S. can play a big role in lowering carbon emissions, but to achieve our country’s climate goals we must deploy 70 GW of solar a year for the next few years.

The U.S. Commerce Department’s preliminary decision on the Auxin Solar Anti-Dumping/Countervailing Duties (AD/CVD) case is not good for the solar industry. By extension, it is not good for our country or our communities. Solar is one of our best tools for reducing carbon emissions. Solar provides a significant boost to our economy, creating good local jobs that can’t be outsourced. And, when paired with energy storage, solar increases resilience for our communities in the face of increasing natural disasters exacerbated by climate change.

The world is not yet on track to limit global warming to 1.5 degrees Celsius compared to pre-industrial levels, but solar can help us change that trajectory. The U.S. can play a big role, but to lower carbon emissions sufficiently and achieve our country’s climate goals, we have to deploy 70 GW of solar a year in the next few years.

At this critical moment in the fight against climate change, we need more solar, not less. The Commerce Department’s decision will slow down solar deployment at a time when we must rapidly accelerate it.

Even before last week’s decision, the AD/CVD case had put a serious damper on the solar industry. In anticipation that the December preliminary decision could impose retroactive tariffs, many manufacturers immediately halted shipments to the U.S. Our industry, already dealing with pandemic-related supply chain and labor issues, saw 24% less solar capacity installed in Q1 2022 than in the same quarter last year. This is the opposite of what was expected and the opposite of what should be happening.

Solar jobs have been growing five times faster than the overall economy and more rapidly than jobs in other energy sectors. Solar installations in 2021 broke records despite the pandemic. But the Solar Energy Industries Association (SEIA) estimated that the AD/CVD case could result in 70,000 job losses and a 46% decrease in solar installations this year and next. Even domestic solar manufacturers anticipated negative impacts from the case.

What makes this even worse is that trade cases generally have little to no positive impact on domestic manufacturing. What does make an impact is supportive legislation. We have that now in the Inflation Reduction Act (IRA), which SEIA expects to lead to a “renaissance in American solar manufacturing.” However, the effects of the IRA will not be immediate. It takes time for a solar panel factory to get up and running. SEIA has been clear that even with the IRA, it will be 2030 before U.S. domestic solar manufacturing reaches the capacity we need for the industry goal of 50 GW.

The Biden Administration’s two-year halt on tariffs, which did provide a reprieve from the worst effects of the AD/CVD case, will only take us to June 2024. That is simply not enough time to establish a robust solar manufacturing capacity in the U.S., which currently produces about 7.5 GW of solar panels yearly. The IRA could increase that number to 15 GW in the next two years, but that would still not be nearly enough capacity to rely solely on domestic panels.

The preliminary Commerce decision could have been worse. The decision did not target all imports from the countries cited in the case, and it left room for companies in those countries to certify that they are not circumventing the AD/CVD orders. But it remains to be seen what will be involved in the certification process. And as SEIA noted, the decision will still “strand billions of dollars’ worth of American clean energy investments and result in the significant loss of good-paying, American, clean energy jobs.”

Just a little over a year ago, the Commerce Department ruled that a similar trade petition had no merit. The current case is based on the false claim that solar cell manufacturing is a minor or insignificant operation in the countries cited; the reality in those countries is that solar manufacturing by far exceeds what is considered minor or insignificant according to the anti-circumvention statute.

With long-term projects making up a significant portion of the solar industry, we need long-term policy certainty, a robust supply chain, and predictable prices. The disruptive AD/CVD case has caused a serious distraction and impediment for our industry at a time when we should be seeing expansive growth.

It’s not too late to change course on this misguided preliminary ruling. Commerce’s final decision on the case is expected in May 2023. The Department can fix its mistake by amending it. If necessary, the Biden Administration can step in again to extend the tariff moratorium. Our nation’s clean energy goals are riding on this.

We must all pull together now to ensure that this baseless case brought by one small solar company does not derail an entire industry. This is the time for solar to shine, and we need to ensure the conditions are right for that to happen.

Scott Wiater is president and CEO of Standard Solar.

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Developers and contractors should create and implement compliance programs to ensure appropriate record-keeping to substantiate their payment of prevailing wages and use of appropriate apprenticeship programs.

Renewable energy developers and contractors have been anticipating the Treasury Department and IRS’s initial guidance on what is required to satisfy the prevailing wage and apprentice requirements under the Inflation Reduction Act (IRA). To take advantage of these tax incentives, renewable energy developers and contractors must ensure their projects meet certain requirements, including paying a “prevailing wage” to workers, employing certain percentages of apprentices, and maintaining required ratios through registered apprenticeship programs.

On November 30, 2022, this guidance was published in the Federal Register. Under the IRA, the prevailing wage and apprenticeship requirements go into effect sixty days after publication, which is January 29, 2023.

While this date is fast approaching, there is no need to panic yet. As an initial matter, the guidance confirmed that projects for which construction begins before January 30, 2023 will be exempt from prevailing wage and apprenticeship requirements and automatically qualify for the 30% investment tax credit. The guidance reaffirmed longstanding pre-IRS rules for determining when “construction begins” – either when physical work of a significant nature begins or, under the safe harbor, when 5% or more of the total cost of the project or facility is incurred subject to continuous construction or efforts requirements.

While many in the renewable energy industry hoped the guidance would provide much needed practical instructions and directives as to how to comply with the prevailing wage and apprenticeship requirements, it is largely a recitation of the IRA provisions themselves, and provides little clarity on implementation. However, the guidance does indicate that the Treasury and IRS may issue later regulations and additional guidance about the prevailing wage and apprenticeship requirements.

So, what does this initial guidance say?

Prevailing wage

The IRA states clearly that laborers and mechanics employed by the taxpayer (the owner of the project when placed in service) and all contractors and subcontractors engaged by the taxpayer must be paid prevailing wages of the locality for the specific profession and classification during construction, alteration, or repair of a covered facility. “Employed” for purposes of prevailing wage requirements is broadly defined, and includes any individual who gets paid money for their services, regardless of whether the individual is an employee or independent contractor under the IRS or other traditional tests. Importantly, based on this initial guidance, and unlike the requirements of the Davis-Bacon and Related Acts (DBRA), the IRA does not appear to require certified payroll be submitted to the U.S. Department of Labor (DOL) – but the guidance otherwise adopts the definitions of some fundamental terms including “wages,” “laborer,” and “construction” from the DBRA.

In describing how stakeholders will determine the applicable prevailing wage, the guidance directs taxpayers to wage determinations published by the U.S. Secretary of Labor at www.sam.gov. If a particular type of construction project, geographic area, job, or classification is not listed there, taxpayers are instructed to request a wage determination or rate from the DOL via email at IRAprevailingwage@dol.gov, making sure to provide enough information in the email (type of construction, geographic area, job description and duties) to assist the DOL in providing a determination. There is no indication in the guidance as to how much time the DOL will be given to respond, or whether there will be a deadline, nor is there indication as to whether the DOL’s judgment calls will be published for other taxpayers who may have similar requests. It does not appear that the process will be as formal as the current Opinion Letter process, and the guidance does not contain the same advisement not to include privacy, trade secretion or confidential commercial information as it may be incorporated into the DOL’s response, which is made available to the public, as the Opinion Letter process dictates.

The guidance admonishes taxpayers to maintain scrupulous records to support or establish that prevailing wage requirements have been satisfied. Although it is unclear whether the records will be subject to an audit initiated by the DOL, developers and contractors should maintain sufficient records in the event of such audit – or more likely, an IRS audit of claimed tax credits.

Opportunity to cure prevailing wage shortfalls

Although the guidance does not expound on the topic, the text of the IRA itself allows a taxpayer to cure a failure to satisfy prevailing wages through catch up payments, with interest, to each worker paid below the prevailing wage and penalty payments to the IRS that amount to $5,000 per affected worker. Higher payments to workers (3x the difference between actual and prevailing wages) and higher penalties ($10,000 per affected worker) apply where the failure to pay prevailing wages is the result of an intentional disregard of the regulations and payments and penalties are due within 180 days of a violation determination.

This opportunity to cure is likely to be a key element of many project agreements during initial implementation of IRA prevailing wage requirements, as developers and contractors negotiate allocation of the risks around assumptions of wage rates prior to DOL determinations.

Apprenticeship

The apprenticeship provisions generally require (1) that a certain percentage of the total labor hours for construction, alteration or repair of a covered facility must be performance by qualified apprentices; (2) taxpayers (and their contractors and subcontractors) who employ 4 or more individuals must also employ at least 1 qualified apprentice; and (3) taxpayers must maintain the required ratio of journeymen to apprentices for the duration of the project. The following journeyman to apprentice ratios apply based on when construction begins:

1. Where the construction begins before January 1, 2023: at least 10% qualified apprenticeship labor;
2. Where the construction begins after December 31, 2022, and before January 1, 2024: at least 12.5% qualified apprenticeship labor; and
3. Where the construction begins after December 31, 2023: at least 15% qualified apprenticeship labor.

Notably, these percentages exclude management and administrative personnel (for example, foremen, superintendents, and owners or persons employed in bona fide executive, administrative or professional capacity).

Like the prevailing wage provisions, “employ” under the apprenticeship requirements is broadly defined and means any individual who gets paid money for their services, regardless of whether the individual is an employee or independent contractor under the IRS or other traditional tests. And, consistent with the prevailing wage provisions, taxpayers are admonished to maintain sufficient records to support that apprenticeship requirements have been met or a good faith effort exception, as described in further detail below, applies.

The guidance further provides that to comply, taxpayers must employ apprentices through a “registered apprenticeship program” meaning one registered under the National Apprenticeship Act or by the DOL. Thus, the taxpayer’s options for apprenticeship compliance are: (1) utilize an established state-registered apprenticeship program; (2) establish your own proprietary program that meets the necessary requirements; or (3) work with industry associations who have existing registered apprenticeship programs.

Good faith effort exception to apprenticeship requirements

A taxpayer will be deemed to have satisfied apprenticeship requirements if the taxpayer requests qualified apprentices from a registered program and receives either no response within five business days of receipt, or the request is denied if such denial is not the result of the taxpayer’s, or its contractors and subcontractors, refusal to comply with the standards of the registered apprentice program.

Overall, while this initial guidance starts the clock toward required compliance with IRA prevailing wage and apprenticeship provisions, it still leaves renewable energy developers and contractors with significant uncertainty in practical compliance.

Remaining uncertainties include:

• What is the process for assessing whether a penalty is owed?
• Is there a timeline within which to expect a response from the DOL regarding wage determination/rate request?
• Will the DOL publish determinations provided in response to individual requests for the benefit of the full industry?
• Are there reporting requirements or new forms or schedules that will be required to certify compliance with prevailing wage and apprenticeship requirements?

As these requirements begin to go into effect, the renewable energy industry will be dependent upon DOL response times to fill in remaining compliance questions and gaps. And we can also expect additional, forthcoming regulations and guidance from Treasury and the IRS.

But for the time being, renewable energy developers and contractors should take note of the following practical points:

1. If your project begins before January 30, 2023, you are exempt from the prevailing wage and apprenticeship requirements.
2. The beginning of construction can be established based on the physical work test or the 5% safe harbor subject to continuous efforts or continuous construction requirements.
3. The DOL has published FAQs for apprenticeship requirements here; and for prevailing wage requirements here.
4. You should keep meticulous records to support that prevailing wage and apprenticeship requirements have been satisfied or that a good faith exception applies. Your records should, at minimum, include the names of workers, duties and responsibilities, work performed, and wages paid for all workers employed on the project.

Now that initial guidance has been issued, renewable energy developers and contractors can put plans in place to implement appropriate structures for compliance with IRA prevailing wage and apprenticeship requirements. Parties should pay particular attention to incorporation of these requirements in EPC and O&M agreements, as well as all downstream subcontracts. Sophisticated developers and contractors should create and implement compliance programs to ensure appropriate record-keeping to substantiate their payment of prevailing wages and use of appropriate apprenticeship programs.

Monica Dozier, Stephanie Gaston, and Amy Puckett are attorneys at Bradley Arant Boult Cummings LLP, who regularly advise clients on labor and employment issues in the renewable energy industry.

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California deserves its shining reputation as an incubator of innovative environmental policies that protect our planet. But the Golden State is now at risk of dimming its own success.

Leading the way on cutting carbon dioxide from electric utilities and automobile tailpipes, California has for years provided financial incentives that make clean energy options like electric vehicles and rooftop solar affordable for millions of working- and middle-class families. These families represent by far the largest block of the million-plus California households that installed rooftop solar, according to the Lawrence Berkeley National Laboratory.

But it could soon be lights out for California’s long, consequential record, which has made the state the nation’s leader in fighting the climate crisis with smart, economically savvy policies. State regulators are proposing to undermine the wildly popular solar program.

The California Public Utilities Commission issued a proposal last month that would slash by a whopping 75% the credits any new solar customers would get for surplus energy their rooftop panels generate and sell back to the grid. The credits are the core of the solar program, which helps budget-conscious families keep their monthly electric bills low and defray the upfront costs of installing solar.

As captive California ratepayers see their bills soar, there’s never been a more important time to promote the climate and economic benefits of rooftop solar. If finalized, the credit cut would put solar financially out of reach for those who are hardest hit by high bills.

Nevada regulators adopted a similar plan in 2015, and the state’s once-flourishing rooftop solar market evaporated almost overnight, as detailed in the Environment California report, Rooftop Solar at Risk.

Allowing the solar market in California to tank too would be a disaster for Gov. Gavin Newsom’s ambitious efforts to reduce greenhouse gas emissions and tackle the worst catastrophes of the climate crisis. We’re already seeing them play out in costly and deadly wildfires often sparked by damaged utility transmission lines and historic drought.

Since the state initiated the residential solar program, annual growth has soared by as much as 62% a year. This is a problem for monopoly utilities, which see their profits threatened as more families and small businesses take advantage of the incentives and install solar, the only source of competition the utilities face.

Pacific Gas & Electric and California’s other two investor-owned power companies are behind the proposal to decimate the solar program, which has helped to install more than 1.5 million homes, small businesses, churches, and schools with solar. The clean energy source makes up about 10% of the state’s electricity generation.

The utilities’ efforts to undermine rooftop solar began a decade ago, when the Edison Electric Institute, the main trade and lobby group for the power sector, delivered a presentation before utility executives warning that increased rooftop solar will lead to “declining retail sales,” and a “loss of customers” and could spell “potential obsolescence” for profit-driven utilities. “Industry must prepare an action plan to address the challenges,” it said.

Restricting rooftop solar and its critical role in helping California fight the climate crisis just to boost utilities’ profits would almost certainly lead to a rise in greenhouse gas emissions. That’s because the power companies would need to expand the use of polluting natural gas to make up for the electricity lost with a plunging solar sector.

California has committed to achieving 60% renewable electricity by 2030, 90% zero carbon energy by 2035 and 100% renewable, zero-carbon by 2045. Its own modeling shows roughly the same amount of rooftop solar must be added each year to meet those goals. Other experts believe far more rooftop solar arrays on homes, schools, businesses, and other structures will be needed to meet those emissions reduction targets.

If Governor Newsom wants to protect his pioneering climate legacy, it’s time for him to flex his political power and demand his hand-picked utility commissioners scrap the solar proposal. Instead, they should start over by identifying ways to make it even easier for struggling California households to reap the benefits of the clean energy source. Let’s keep rooftop solar growing and ensure California’s bright environmental leadership shines on.

Ken Cook is president of Environmental Working Group and Laura Deehan is executive director for Environment California.

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The digital transformation of scalable and cost-effective solar manufacturing is key to enabling the anticipated growth in clean energy alternatives.

Climate change and energy crises continue to dominate headlines and exert pressure to produce clean energy alternatives to fossil fuels. With policy developments in the United States, such as the passage of the Inflation Reduction Act, investments in domestic manufacturing appear to be set to grow at an unprecedented pace as manufacturers work to meet the moment with expanded capacity.

From a production standpoint, the key to enabling this growth efficiently and sustainably lies in digital transformations for scalable and cost-effective manufacturing of solar energy components. Let’s examine the hyperautomation and digital twin initiative we undertook at First Solar (Nasdaq: FSLR), for a master class in how the industry can optimize production, drive cost per watt down and shorten energy payback time.

Factory of the future

All manufacturers struggle with modern challenges that include pandemic-related production slowdowns, talent shortages, high sourcing costs and overall supply chain upheaval. For solar technology manufacturers like First Solar, the last two years have prompted a pivot away from the legacy approach of hub-based manufacturing and towards the strategic siting of new manufacturing capacity close to demand.

In such a pivot, competitiveness is enabled by enhanced efficiencies, which, in turn, require digital transformation and automation to modernize the solar manufacturing environment. This was the goal of First Solar, the only U.S.-headquartered company among the world’s ten largest solar manufacturers and a leading global manufacturer of advanced thin film photovoltaic (PV) technology. With a fully vertically integrated manufacturing process that is among the most advanced and efficient in the solar manufacturing industry, First Solar is uniquely suited to further embrace digital transformation to create a “factory of the future.”

A factory of the future is founded on breaking down information silos and streamlining the flow of data – from the shop floor to the top floor – to enhance visibility and intelligent decision support across all manufacturing and operations. Organizations that succeed in this create what’s known as digital thread, a seamless flow of data that runs through the entire organization.

Digital thread, in turn, brings to life digital twins. These virtual replicas of physical operations are finely detailed and exact in mirroring and predicting impacts to any contemplated changes in workflows, machinery, controls and systems. Mature digital twin capabilities can support virtual commissioning and emulation of PLC codes, immersive instruction and training visualizations for equipment operators, advanced design prototyping, and other capabilities that optimize production.

These advantages are amplified in solar production. That’s because panel manufacturing is mid-to-high volume, with processes and workflows that First Solar sought to optimize through faster cycle times, higher cascade yields and industry leading tact times. Production flow throughout the factory is critical to achieve peak throughput, and First Solar saw an opportunity to leverage virtual testing of layout design and control strategies to maximize production throughput.

With the help of Kalypso, First Solar laid out a strategy to leverage digital twin and related smart manufacturing systems for a more connected, data-intensive operation that would provide unprecedented visibility and control around production flow of current and future operations. Added capabilities include advanced analysis of production data to predict and prevent issues; closed-loop auto-resolution of production anomalies; and enhanced visualizations like immersive virtual reality (VR) tools to streamline collaboration and triaging of issues.

Real-world benefits

The digital transformation efforts, including the benefits of digital twins, enabled First Solar’s efforts to scale manufacturing of responsibly produced PV modules that support America’s transition to a decarbonized future. This helps First Solar improve productivity while achieving significantly lower costs, waste, and energy payback times.

To fully understand the application and benefits of the technology, the Kalypso team worked with First Solar to develop and deploy a digital twin pilot to a bottleneck part of an existing factory that was being retooled. A digital twin was used to simulate infeed/outfeed and material handling of the area including identifying optimum routing of the solar panels and placement of a buffer to maximize production output. This model also helped test multiple scenarios and proactively anticipate bottlenecks in the area. All of this was done virtually using a digital twin that replicated production line scenarios.

Based on outcomes of the pilot phase, a digital twin is being developed to optimize operations across First Solar’s newest manufacturing factory in Ohio, which is expected to come online in the first half of 2023. Virtual modeling helps inform production layout and processes for all 20 manufacturing zones that make up the factory – optimizing everything from workflows and equipment placement to materials transfer, maintenance cycles and more. Throughout, First Solar uses “copy smart” factory scaling techniques to ensure manufacturing of solar modules is done with the same process and equipment in each factory, yielding the same results no matter where a particular module is made.

Innovation at a critical moment

The solar industry is at an inflection point as the sector navigates a confluence of external conditions. The combination of demand driven by the economics of solar, long-term policy, and the urgency of climate change is driving activity across the industry and its value chains. However, it is essential that this growth is sustainable, efficient and capable of not just meeting the moment today, but of addressing tomorrow’s needs with high quality, competitive manufacturing and supply chains.

Fortunately, digital twins and other digital initiatives for intelligent operations are here to help in solving these pivotal challenges of efficiency and scale – strengthening a solar manufacturer’s handling of everything from responsible manufacturing and product performance, all the way to end-of-life management and recycling.

As First Solar has shown through its own pioneering efforts, digital twin capabilities translate into lower costs, reduced waste, and vastly improved productivity – all of which helps the solar industry rise to the occasion.

Jay Mehta Image: First Solar

Jay Mehta is the head of global manufacturing engineering at First Solar, and is responsible for setting the automation roadmap and new technology direction for First Solar manufacturing. Jay has more than 16 years of experience in high-tech manufacturing including prior experience in Semiconductor manufacturing.

Chad Markle Image: Kalypso

Chad Markle is principal, global commercial lead at Kalypso. Chad has over 25 years of experience working as an executive and advisor in technology-driven industries to deliver results by combining strategic thinking with the transformative business impact of technology. He leads the global commercial operations for the entire Kalypso business across industries, capabilities and geographies; helps clients to achieve digital transformation of the value chain; and works to build the future leaders of Kalypso.

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How to avoid critical mistakes when planting pollinators for solar projects.

There’s a lot of buzz these days about planting pollinators with solar panels — for good reason. Incorporating pollinators provides a slew of benefits for solar installations, agriculture, and the environment. But it’s not as simple as scattering some seeds and hoping for the best. Luckily, through extensive experience and research, we have arrived at best practices that will set you up for success. Inovateus Solar and The Bee & Butterfly Habitat/Conservation Blueprint recently conducted a webinar about these risks and benefits, and the following is a summary of those guidelines that will help avoid common pitfalls.

Why plant pollinators?

Solar developers can make a positive environmental impact by planting pollinators around solar panels. Pollinators do more than just provide habitat for bees, butterflies, insects, and other wildlife. They also sequester carbon, help prevent stormwater runoff, and reduce the use of fertilizers, herbicides, and pesticides; resulting in improved water and soil quality.

What may not be as obvious are the many benefits pollinators provide to solar installations. Pollinator plants can decrease the ground temperature under solar panels, helping panels work more efficiently and produce more power. They can also reduce maintenance costs for solar farms, because mature pollinators require far less mowing than other ground covers.

The benefits don’t stop there. As more solar farms are being developed, many have been facing local opposition. Residents may be concerned that the solar farms will use valuable farmland, ruin views, or change the character of their community. Pollinators can help in several ways, such as by improving solar farm aesthetics. Beekeepers can keep hives around solar pollinator fields to help with honey production. And bringing more pollinating insects to a region helps increase yields for nearby farms. Seeing all these benefits can help communities get on board with solar farms.

As a testament to the benefits, Inovateus Solar, a national solar developer and EPC, has made a commitment to planting pollinators as part of its sustainable solar development. This year, the company has aimed for at least 75% of its solar sites to include pollinator habitat. Inovateus isn’t alone; the trend is becoming popular among solar developers across the U.S. But without the right guidance or experience, it’s easy to go astray — with potentially costly mistakes.

Early planning

That’s where Conservation Blueprint comes in. The company, which creates custom seed mixes for pollinator habitats, has extensive experience tailoring the mixes to the specific needs of solar developers. This is more complex than it might seem; a great overall seed mixture for pollinators might not work well for a solar installation.

Getting it right requires early planning — ideally, before the project has even started. Think of the vegetation as being as important as the electricity that will be generated by the solar panels. The earlier in the process vegetation is considered, the more successful the planting will be.

It’s crucial to involve all parties in these early discussions: the seed mixture designer, the solar developer, and whoever will manage the vegetation.

Panel height

One of the most important things to consider early is the height of the panels in the project.

The utility-scale solar industry is moving to a standard of a lower panel height of 20 to 24 inches off the ground. Many pollinator plants grow taller than this, so they would shade the panels.

Limiting the plant height to species that don’t grow taller than 18 to 24 inches takes a lot of tools out of your toolbox, but you may be stuck with that if panels are too low.

A project with a 36-inch lower panel height may be much better suited to pollinator plants. Those 12 inches make a big difference in designing a seed mixture. The good news for solar developers is that the cost difference between 24 inches and 36 inches is minimal.

Site preparation

The next step in early planning is to prepare your site. That might mean removing any existing vegetation. If the site was formerly used for agricultural production, you will need to control the weeds that will grow on the site.

Site preparation can include establishing the pollinator plants before construction. The advantage to waiting until after construction is that you won’t need to replant some of what was planted earlier. But unless a site requires significant grading or you expect to have to replant more than 30% of the site, it’s cost-effective and much easier to establish a uniform pollinator ground cover prior to construction. For that reason, many projects are going this route.

Vegetation management

A vegetation management plan is essential to guide you through details such as site preparation, timing of the planting, method for planting, and determining what equipment to use. Although the pollinator plants account for a tiny fraction of the total project budget, the whole project can be thrown into disarray if the final vegetative cover is not established.

It’s recommended that once it’s established, pollinator habitat be mowed 9 to 12 inches from the ground rather than close to the ground. Timing is key. Mowing weeds before they get out of control is essential while the pollinator plants are still establishing themselves.

Seed selection

Native wildflowers are nice to look at, but they’re not always suited to solar sites. Many don’t tolerate being mowed once or twice a year, and some may grow too tall for your panels. On the other hand, some local ordinances require that you establish vegetative cover using only native plant species, so you should check to see what’s required in your region.

A well-managed solar site may often use white Dutch clover, which Conservation Blueprint often combines with fescues and bluegrass for utility-scale solar farms that have a lower panel height of 20 to 24 inches.

The mixture has a very high seeding rate and establishes itself quickly. Clover, though it doesn’t qualify as a native plant, is highly beneficial to pollinators. But for the maximum benefit to pollinators, it’s best to establish two different seed mixtures for a site. The clover mixture can be used around the panels. Areas on the site without panels, usually about 10% to 20% of a utility-scale project, can be planted with a more traditional pollinator seed mixture that has a minimum of 40 native wildflower species. This approach works best for sites that are at least two acres in size.

About 16 states have solar pollinator scorecards that can help guide you in selecting the optimal seeds for your site. You also want a seed mixture that’s adapted to your site’s soil type and geography.

Conservation Blueprint considers these additional factors when designing an optimal seed mixture:

• Pollinator value. Just because a plant produces a flower doesn’t mean it has great pollinators.
• Project budget. The cost of the seed mixture needs to fit into the total budget.
• Seed availability. Supply issues apply to seeds, too! It’s essential to select a seed mixture with enough available seeds for the project.
• Ease of establishment. Your EPC might want pollinator plants that become established quickly, so they can turn the project over quickly.
• Longevity. If your project has a 30-year lease term, you want a seed mixture that will last and perform well for 30 years.
• Shading tolerance. The pollinator plants seeded within the array area must be able to tolerate some shading.
• Albedo effect. Ideally, the seed mixture that goes under the panels will reflect more sunlight from the ground up, known as the albedo effect. This can help bifacial panels produce more energy.
• Fire resistance. It’s often desirable for a seed mixture to have some resistance to fire.

The future of solar pollinators

The use of pollinator plants with solar continues to be studied. In 2023, the Bee and Butterfly Habitat Fund will begin a program to establish high-quality pollinator habitat with utility-scale solar projects. The program will monitor pollinators such as milkweed for five years and will monitor carbon sequestration at each project for at least six years to determine which seed mixtures work best for that purpose.

But you don’t need to wait for further studies like these to start incorporating pollinator plants into your projects. Following the best practices outlined here will ensure that your solar pollinator efforts bring significant benefits to both your projects and the regions where they are located.

The information in this article is based on a co-webinar presented by Inovateus Solar and The Bee and Butterfly Habitat Fund in November 2022. You can watch a replay of the full webinar here.

Tyler Kanczuzewski (left), is vice president of sustainability for Inovateus Solar.

Peter Berthelsen (right) is president of Conservation Blueprint

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