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.

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.

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.

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.

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.

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.

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.

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. 

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.

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. 

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. 

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.

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.

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.

It was not until 1982 that NERC (North American Reliability Corporation) started GADS (Generating Availability Data System), a database about the performance of electric generating equipment that supports equipment availability analysis. Through GADS, NERC maintains operating information on conventional generating units, wind plants and solar plants.

Today there is information on over 5,000 generators in the GADS database, and that number is soon to go up with the changes in regulations. Starting in January of this year, solar facilities over 100 MW of total install capacity were required to report to GADS and that threshold will be lowered to 20 MW in January of 2025.

GADS reporting is separate from the upcoming NERC applicable changes. The NERC rules ensure that elements of the Bulk Electric System operate in a way that is safe and reliable for all that use it. GADS is an arm of the NERC organization that began collecting design, performance, and event data into a singular location to analyze and identify if there is a holistic problem across different utilities, different generators, transmissions, etc. To see trends, you need as much data as possible, hence the inclusion of smaller facilities.

Loggan Purpura Senior Manager of Compliance with Radian Generation said “A few months back I determined that a specific solar panel had an issue with reduced capacity, but it was only because we had the exact same issue on two sites. GADS is collecting thousands of site data, so if they detect a material defect across multiple sites, they can quicky alert owners to the issue. This is extremely helpful to all parties and is helpful in building grid reliability.”

What kind of information is GADS looking for?

GADS will require quarterly reporting, with reports due 45 days after the end of a quarter. If you do not have a plan for these reports, it is time to put one together. The first challenge is data collection. How will you collect the data for the report? What stakeholders are included in the process? Who will collect the data?

GADS will require you to collect three types of data: design, performance, and event data. Design data is basic information about the site, such as plant information, inverter group, and energy storage, if applicable. Other information includes location, elevation, the nearest city, the ownership structure of the site, equipment identification manufacturers, and model numbers. If you have PV trackers, reporting includes the angle, the stove speed, the minimum irradiance you expect to see performance from. All this detail from the design side, gives a baseline or context for performance data, that will be beneficial to all owners and operators.

GADS also collects a wide range of data from the performance of the site such as gross power generation, maximum capacity, active solar inverter hours, forced outages, and more. When there is a reduction in plant output below a certain level or an outage, GADS will ask generators to report on those specific events. They will want a significant amount of data on events, whether they are outages or derates to better understand and improve the industry.

While regular reports are something your facility can anticipate, an event report, can catch you off-guard if you do not have a process in place. Outages or decrease in plant output of more than 20 MW, will require event reporting, and include information on equipment failures, or grid event circumstances or whether it was planned maintenance or a forced outage.

Be sure to validate your data

It is important to plan for data validation. Is someone going through the data to check for accuracy before it is reported? Be sure to have various checks in place to make sure you are reporting quality data. There will be eyes on what you report and regulatory scrutiny to ensure you are reporting the correct data, so validating your data must be an integral part of the process. There is data management software, including Radian Digital that is designed specifically for renewables and can help identify anomalies, in addition to streamline data acquisition from multiple sources, visually enhance analytics, and facilitate timely accurate reporting.

Data validation provides cleanness, accuracy, and completeness to a dataset by eliminating errors and ensuring the information is not corrupted. Without it, a service like GADS might rely on insufficient data to make conclusions about the grid. For example, data outside certain ranges should produce red flags, and some data can be checked against historical records for validation.

Consider voluntary reporting to work out the kinks

While GADS reporting for 20MW facilities will only be required in January 2025, voluntary reporting for Q3 and Q4 will allow organizations to identify and address any issues before they become serious compliance concerns. The initial setup takes more time, and by doing a voluntary submission organizations will be able to work out the kinks and streamline the process internally or determine if they need outside help.

One challenge for many facilities is that the reporting can be incredibly dynamic, meaning there is data that businesses are not accustomed to pulling. For example, there may be aspects of your operation that are not easily available, and you will have to find a way to isolate that data and put it into the correct format for the GADS system. For example, inverter maintenance hours vs. planned inverter maintenance hours.

For organizations that choose to outsource GADS and NERC reporting, be sure to get a customized strategy that includes internal controls, reporting, documentation of all data for validation, and overall risk reduction. This will help with efficient data collection and reporting, regulation interpretation, error avoidance, proactive problem-solving, and resource optimization.

Purpura said “Most industries report on similar types of information, but it is usually a handful of volunteer companies reporting, or the top ten, or a dozen diverse companies sharing their observations, which is not a comprehensive approach. What NERC is striving for through GADS is the single best way for the entire industry to understand the real impacts of renewable energy. And for owners this should result in valuable data to help improve performance and inventory management, predictive maintenance, and of course the transition to clean energy.”

NERCs mission is to have a reliable grid, and GADS is recognized as a valuable source of information about reliability, availability, and maintainability – a key component to achieving this mission. By quickly identifying industry wide trends NERC can help owners and operators optimize performance and develop better facilities.

Building a culture of compliance and starting voluntary reporting today is a smart move, so that when 2025 is upon us, those facilities will already be accustomed to the requirements, and GADS is just another quarterly report.

Kellie Macpherson is executive vice president compliance & risk management  with Radian Generation. She oversees NERC compliance and managed security services. For over 15 years, she has been a noteworthy leader in the renewable asset space and has implemented 200+ compliance programs and completed 40+ NERC audits in all six NERC regions.

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.

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?

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. 

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. 

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.

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.

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.

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.

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.

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.

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. 

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.

3. 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.

4. 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. 

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.

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.

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).

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.

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.

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.

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.

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. 

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.

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.

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.

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 1/5^th 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. 

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.

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.

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.

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.

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.

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)

The 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

1. 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.

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. 

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.

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.

‘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.

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.

‘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.

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.

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. 

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 technology
A 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.

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.

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.

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:

• 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.
• 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]
• 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.
• 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.

3. Module due diligence should confirm:

• 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).
• 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.
• 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.

‘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).

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. 

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.