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. 

The Global Polysilicon Marker (GPM), the OPIS benchmark for polysilicon outside China, was assessed at $22.567/kg this week, reflecting stable market fundamentals.

Industry insiders in the global polysilicon market are currently upset by the news of a delay in the preliminary ruling results of U.S. investigations into imported cells and modules from four Southeast Asian countries.

According to a source, the deadline for the countervailing duty investigation, originally expected around July 18, has been delayed to September 30. The preliminary results of the antidumping duty investigation, initially expected at the start of October, are now anticipated to be delayed by a week, with the possibility of further extension until the last week of November.

Other sources concurred, with one noting that “being postponed to November is a high probability event.” It is highly likely that the U.S. will wait until after the 2024 presidential election to release the specific results of the tariffs, the source added.

Another industry insider noted that the uncertainty surrounding major integrated manufacturers exporting modules to the U.S. has prompted them to consider every way possible of postponing their monthly purchases of global polysilicon secured with suppliers under long-term contracts during this period.

Uncertainty about the operations of these major enterprises has also intensified as a result. “Given that high gross margins from U.S. module prices are currently the only significant source of potential profitability for supply chain manufacturers, they can’t afford to abandon this market, despite the increasing trade barriers,” said an industry insider. The source added that more module manufacturers are reportedly delivering small module orders by paying a deposit at U.S. customs during this window.

The global polysilicon market is poised to endure another two to three months of a prolonged “winter chill”, a market observer concluded, noting that during this period, minimal price fluctuations are anticipated due to subdued market activities.

A market observer offered a long-term perspective, suggesting that with the support of U.S. trade policies, demand for global polysilicon should remain steady in the coming years. The next major factor likely to influence global polysilicon prices will be changes in the supply-demand dynamics between global polysilicon production and newly established ingot capacities outside of China and the four Southeast Asian countries – a shift that may only become significant after a few years.

China Mono Grade, OPIS’ assessment for mono-grade polysilicon prices in the country, remained steady at CNY 33/kg ($4.60/kg) this week, marking the tenth consecutive week of stability. China Mono Premium, OPIS’ price assessment for mono-grade polysilicon used for N-type ingot pulling, is reported at CNY 39/kg ($5.44/kg). Sources indicate that Chinese polysilicon manufacturers are still grappling with ongoing production cuts and persistent cash losses.

According to an upstream source, a major Chinese polysilicon producer with an annual capacity of 300,000 mt has scheduled only 13,000 mt for August. Similarly, another leading manufacturer of comparable scale plans to produce 8,000 mt in August.

Recent market consensus suggests that polysilicon prices have bottomed out and are unlikely to decline further, leading to reports of wafer companies and traders beginning to stockpile polysilicon.

According to a market participant, wafer companies are increasing their price inquiries for polysilicon, and some with stable cash flow have expressed intentions to stockpile, although no concrete actions have been observed yet.

“A slight rise in offers from some polysilicon manufacturers has already been seen this week, though this increase has not yet impacted actual transaction prices,” the source added.

Spot and futures traders have also boosted their inquiries concerning polysilicon prices. Multiple sources have disclosed to OPIS that China’s polysilicon is set to be listed as a futures commodity in October. This development could prompt some traders to hoard and build inventories, potentially driving up polysilicon prices.

Nevertheless, according to a market survey done by OPIS, there are still some industry insiders skeptical that listing polysilicon as a futures product will have a major positive impact on price increase.

“Given the current supply and demand scenario, I believe that listing polysilicon as a futures commodity will not result in a major increase in pricing, as the difficulty of driving up polysilicon prices is matched by the challenge of reducing polysilicon inventory,” a market source commented. “At the moment, the polysilicon inventory of 200,000 to 300,000 mt is massive, and it is improbable that all of it would be hoarded by dealers; not to mention that polysilicon production is still ongoing.”

Another market source offered a different perspective, noting that the success of listing polysilicon as a futures commodity also hinges on support from major polysilicon producers. If current low prices persist, these leading producers could potentially drive smaller competitors out of the market. However, listing polysilicon as a futures commodity might absorb surplus production capacity, potentially leading to a price rebound and providing a lifeline to smaller producers – a scenario that major producers are currently hesitant to support.

In the early stages of listing a product as a futures commodity, market operations are often underdeveloped, a market veteran commented, adding that this is particularly true for polysilicon, a product with only a few market participants and easily manipulated prices. “Given the current inactivity in the polysilicon market, it may not be an ideal time for a futures commodity launch, thus a major price shift is not predicted,” the source concluded.

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.

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. 

Prices in the Chinese cell market were assessed lower week-to-week reflecting buy-sell indications. The FOB China Mono PERC M10 cell and TOPCon M10 cell prices were assessed down 2.64% at $0.0369/WW while the FOB China Mono PERC G12 cell prices were assessed lower by 3.29% at $0.0382/W week-to-week.

Market activity remained quiet as the majority of market participants continued to stay on the sidelines, adopting a wait-and-see approach. While prices had already reached their lowest point, falling 59-63% year-to-year on July 30, according to OPIS data, expectations of further price declines kept most buyers away from the market.

In the domestic market, some sellers had reduced prices of Mono PERC M10 and TOPCon M10 to CNY0.29 ($0.040)/W while others kept prices stable at CNY0.30/W. The prices of Mono PERC M10 and TOPCon M10 cells were assessed at CNY 0.298/W, down 2.3% week-to-week. Prices of Mono PERC G12 prices were lower by 3.1% at CNY0.308/W.

China produced a total of 310 GW of cells in the first half of 2024, an increase of 37.8% year-to-year despite attempts by cell manufacturers to reduce cell production in June and July in a bid to curtail the oversupply situation in the market.

Although cell exports for the same period rose 26.2% to 142.16 GW, achieved sales prices were much lower compared to a year ago, resulting in tighter margins for cell manufacturers, an industry source said. The industry is experiencing a stage of persistent low prices throughout the solar value chain and if this should continue for long, the industry could be headed for a consolidation faster than expected.

Meanwhile, cell manufacturers continue to cut production rates in a bid to restore market supply and demand balance. China’s cell production in July was expected to reach 49-51 GW, down from 53 GW in June, 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.

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.

From pv magazine Global

As the global energy landscape shifts towards renewable energy sources, effective reactive power management becomes critical for ensuring grid stability and reliability. The recent report by IEA PVPS Task 14, “Reactive Power Management with Distributed Energy Resources,” delves into state-of-the-art practices, best practices, and recommendations for managing reactive power amidst the growing integration of distributed energy resources (DERs). This article provides a comprehensive overview of the report’s findings, regulatory frameworks, and practical applications, underscoring the essential role of reactive power management in maintaining a stable and efficient power grid.

The Importance of Reactive Power Management

Reactive power management is essential for maintaining voltage control, ensuring high power quality, and enhancing overall grid stability. It helps prevent issues such as harmonics, flicker, unbalanced loads, and power oscillations, which can negatively impact power quality and the ability to transfer power effectively. With the increasing integration of DERs like photovoltaic (PV) systems, these resources must assume greater responsibility for providing reactive power control. This improvement in power system stability is crucial for preventing problems like load shedding and system collapse, ultimately enhancing the security and reliability of the power system.

Objectives and Purpose of the Report

The IEA PVPS Task 14 report aims to provide a management summary on the state-of-the-art practices, best practices, and recommendations for reactive power management. It explores regulatory frameworks in selected countries, highlighting diverse approaches to managing reactive power. The report offers insights into the current state and future prospects of reactive power management in the context of increasing DER integration and investigates the effectiveness of various regulatory frameworks in supporting reactive power management.

Regulatory Requirements and Practices

The report covers the regulatory requirements in selected Task 14 countries and research and application examples from these countries. It provides an overview of reactive power regulations across various countries, detailing grid codes and frameworks that shape the requirements for connected DERs to provide reactive power control. Task 14 exemplarily examines how these regulations influence the operation of power systems with increasing integration of renewable energy sources. As an example of the regulatory requirements, Germany will be mentioned in this article.

Example: Germany’s Grid Codes for DER Reactive Power Provision

In Germany, current grid codes mandate that DERs must provide controllable reactive power during feed-in times. The guidelines ensure that DERs contribute effectively to grid stability by providing necessary reactive power. This capability allows Distribution System Operators (DSOs) to utilize DER for additional system services. The requirements vary based on the voltage level:

• Low Voltage (LV): VDE-AR-N 4105 specifies that DER with a capacity of ≤4.6 kVA must provide reactive power with a minimum power factor of 0.95, while larger DER should provide a minimum power factor of 0.9.
• Medium Voltage (MV): VDE-AR-N 4110 requires DER to maintain reactive power within a fixed range when active power feed-in exceeds 20% of installed capacity, ensuring stability at the point of common coupling (PCC).
• High Voltage (HV): VDE-AR-N 4120 offers three options for reactive power provision based on the generator’s active power feed-in and capacity. Each variant specifies different overexcited and underexcited power factors, allowing DSOs to select the most suitable option for their specific needs. DSOs can select one of the suggested options based on the specific circumstances at the PCC of each generator. HV and extra high voltage (EHV) level generators must be able to provide reactive power within one of the fixed reactive power ranges if their active power feed-in exceeds 20% of their total installed capacity.

One common characteristic is that there are just minimal or no reactive power requirements when feeding in small active powers. The different demanded reactive power capabilities are summarized in Figure 1.

Selected Case Studies

In Germany, the case study focus is on forecasting the reactive power flexibility potential of medium-voltage (MV) PV plants. The study evaluates various PV forecasting approaches and introduces a reliability indicator to assess the accuracy of reactive power flexibility forecasts. This emphasizes the need for high reliability in forecasts to prevent overestimation and explores the use of a reactive power planning reserve to enhance forecast reliability. This especially corresponds to times of low active power infeeds as mentioned in the previous section and emphasizes the importance of continuous updates of grid codes as indicated in the Task 14 PV ancillary services report.

Japan’s approach involves evaluating voltage control performance under different scenarios, considering the increasing PV penetration. The study, conducted by a consortium involving TEPCO Power Grid and Waseda University, supported by NEDO, assessed voltage control under fixed power factor control. The findings led to a new grid code in 2023, stipulating that power factor settings must be adaptable based on DSOs’ requests, highlighting the need for flexible control strategies.

Austria’s study focused on the effectiveness of future network-related measures in low-voltage grids. It evaluated various scenarios, including the impact of climate policies, regional technology rollouts, and different operating strategies related to PV, heat pumps, and e-mobility. The study identified challenges such as the need for detailed analysis of Q(V) control contributions and the lack of large-scale grid simulation capabilities, which hinder a comprehensive understanding of reactive power management’s value in distribution grids.

Key Takeaways from the Report

The report’s main authors highlight three key takeaways. Firstly, there is a need for updated regulatory frameworks to align with the evolving energy landscape, ensuring the resilience and efficiency of power systems. Secondly, the potential of DERs as a source for reactive power services should be further explored, including enhanced integration of solar PV forecasting. Thirdly, collaboration between Transmission System Operators (TSOs) and DSOs is essential for effective reactive power management, which could be enhanced with Information and Communications Technology (ICT).

Conclusion of Task 14 and Future Directions

Task 14 has concluded after 14 years of successful research and development in the field of PV integration and reactive power management. Throughout its three phases, Task 14 has made significant strides in addressing technical challenges, developing standards, and promoting best practices for high penetration of PV systems in electricity grids. As Task 14 ends, its legacy continues to influence grid management and renewable integration strategies.

Looking forward, Task 19 will commence in 2025 as a follow-up to Task 14, building on its achievements and continuing the mission of enhancing grid stability and efficiency with increased renewable energy integration. Task 19 will focus on managing grids with 100% renewable energy sources, integrating solar PV with wind, and defining the role of solar PV in the smart grid.

Find more information on IEA PVPS Task 14 and all of their publications here.

From pv magazine Global

FOB China prices for wafers have remained stable across the board this week. Mono PERC M10 and n-type M10 wafer prices held steady at $0.141/pc and $0.139/pc, respectively. Likewise, Mono PERC G12 and nN-type G12 wafer prices remained unchanged at $0.209/pc and 0.205/pc, respectively, compared to the previous week.

Although there have been reports that n-type M10 wafer prices might increase due to the switch in China’s domestic wafer production lines from full square wafers sized 182 mm x 182mm to rectangular wafers sized 182 mm x 183.75mm and 182 mm x 210mm, actual transaction prices have remained unchanged except for a few companies’ increased offers.

“Given the sluggish downstream demand and the losses suffered by downstream companies, it is impossible to expect them to accept rises in upstream material costs,” a market source stated.

In contrast, the prices of n-type 210mm wafer set, including the full square 210 mm x 210mm wafers and rectangular 182 mm x 210mm wafers, have softened twice in the past month, according to the OPIS data. Industry insiders attribute this to a shift in production capacity from the 182mm set to the 210mm set, leading to increased inventory of the latter.

“As the market share of a size grows, its inventory rises and prices decrease, which the 210mm wafer set is currently experiencing,” a market observer commented.

According to the OPIS market survey, the majority of wafer operating rates in China’s domestic market are at 50% or lower, with the exception of a Tier-1 wafer producer and one big specialized wafer producer who maintains operating rates of more than 90%.

“Some integrated manufacturers who have halted in-house wafer production due to low market prices, are now sourcing most of their wafers from these two producers,” said a market participant.

A leading Chinese wafer manufacturer announced last week that it will establish a 20 GW ingot and wafering capacity in Saudi Arabia. According to an insider, it is expected the construction to begin this year, with completion and operation slated for 2026.

High gross margins from U.S. module prices are currently the only significant source of potential profitability for supply chain manufacturers, according to a market veteran, noting that this wafer project is expected to target the U.S. market in the future, potentially sourcing polysilicon from the three existing global polysilicon suppliers, the Oman and the UAE polysilicon plants yet to produce, and traceability-compliant Chinese regions.

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.

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 utility-scale solar energy sector is rapidly evolving, with many innovations aimed at reducing costs and increasing efficiency. One such innovation is fully integrated switchgear skids – which consist of transformers plus switchboards and SCADA – produced in a factory setting as opposed to integrating these components in the field.

By integrating these components in a factory setting, you can streamline installation processes and save tens of thousands of dollars. This is made possible by reducing costly field labor, conduit and wire, including through the skidded switchboard, in which the MVT is direct bussed. This is accomplished all while delivering the highest quality installation on projects. Castillo Engineering, Recon Corporation, EPEC & ReBoSS are achieving these benefits today by designing and building fully integrated transformer (XFMR) / switchboard (SWBD) skids in a factory rather than at solar sites.

Understanding Switchboards in Solar Projects

Low voltage switchboards are a crucial component in electrical systems, consisting of the busbar, circuit breakers, and protective relays that control, protect, and isolate electrical equipment. In solar projects, switchboards play a vital role collecting the power from inverters, and tying that power into the electrical grid. By integrating switchboards into the design phase & building them into skids in a factory before arriving on-site, you can significantly reduce costs, expedite project timelines, and improve your solar energy system’s overall performance and reliability. Avoiding over-specification in fault current ratings is critical.

Benefits of Integrating Switchboards into Solar Designs

1. Shortest Lead Times

Integrating the XFMR, SWBD, and SCADA in a factory setting is not subject to weather and other supply chain issues that often plague completing this integration at a solar construction site. For this reason, EPEC, ReBoSS and Castillo Engineering ensure the shortest construction build times in the industry for developers and EPCs like Recon Corporation. Also, this reduction in construction time due to lack of weather and labor delays means the developer can cease their construction loans faster, which increases the solar project’s profitability.

2. Highest Quality Installations

ReBoSS and EPEC are highly competent in designing & delivering fully integrated XFMR/SWBD skids custom-designed to power renewable energy projects. Over the years, EPEC has built a specialized team that ensures that the highest quality XFMR/SWBD skids can arrive on time and with superior quality assurance and quality control. Unlike when switchgear, transformer, and other components are integrated on the pads in the field, completing this integration in a controlled environment, factory setting with a highly trained team dramatically increases the quality control and it lessens the time required to complete the switchgear integration.

3. Reduced Installation & Equipment Costs

Integrating switchgear onto skids within a factory setting versus in the field yields significant cost savings. Pre-integrated systems reduce labor costs because labor hours spent in a factory to install switchgear are less than the time spent integrating the same equipment in the field. EPEC, ReBoSS and Castillo Engineering customers have reported saving between $9,000 to $20,000 per transformer/switchboard connection when using a direct bus versus the typical cable connection.

With the direct bus and skid connection, there is a significant reduction in cost because there is less conduit, wire, and labor to procure compared to the direct bus connection alternative. Close-coupling the XFMR & SWBD and integrating it on a skid significantly reduces the scope of work and time required for the highly specialized medium voltage labor to complete this switchgear integration in the field. This avoids unnecessary, extremely labor-intensive elements that would otherwise elongate schedules from weather delays, including excavation, pad forming, conduit installation, equipment setting, cable pulling, an excessive amount of high ampacity cable terminations, and equipment grounding conductor runs.

4. Maximum Tax Savings

The new Inflation Reduction Act (IRA) law allows for “manufactured” equipment with domestic content to be counted as part of the percentage required to qualify for the additional 10% “domestic content” incentive. Equipment that is built on a solar site is not considered “manufactured equipment” and therefore cannot be counted toward the domestic content percentage, which is presently at 45 percent for 2025. Integrating the switchboards onto a skid in a factory setting meets this manufactured equipment definition. As a result, solar developers can add this equipment to their tally and possibly leverage the additional IRA 10 percent tax incentives to maximize the project’s financial returns.

5. Simplified Maintenance

A well-integrated switchboard system simplifies maintenance and troubleshooting. A comprehensive design that includes switchboards from the outset makes it easier to identify and address issues, reducing downtime and maintenance costs. This ensures that the solar plant operates smoothly with minimal interruptions. An above-grade bus throat will have fewer issues than below-grade circuits over the life of the farm.  Even if there is an issue down the road, it is much simpler to troubleshoot/repair.

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.

Prices in the module market were assessed stable-to-soft for the second consecutive week. The Chinese Module Marker (CMM), the OPIS benchmark assessment for TOPCon modules from China was assessed at $0.096/W, down $0.002/W reflecting discussions heard while Mono PERC module prices were assessed stable at $0.090/W from the previous week.

The TOPCon market was rather “chaotic” in the week to Tuesday with prices heard in a wide range. Some Tier 1 module manufacturers continued to offer cargoes at $0.100/W FOB China while lower offers from Tier 2 and Tier 3 module sellers had emerged at $0.085/W FOB China. These low prices were “distorting” the market and creating a false impression that mainstream TOPCon prices had rapidly fallen so low in a short period of time, a market source said.

Market participants OPIS surveyed expected further declines in TOPCon prices in the coming weeks as module makers compete to secure new orders and clear inventories. Although module makers are already burning cash and there is a limit to how much lower prices can fall, Tier 1 players are in a better cash flow situation compared to the smaller players in the market. However, several big players have already announced losses in the first half of the year and if this vicious cycle of non-stop price war continues, the industry will start to see a market consolidation very soon, an industry source said.

Business has slowed considerably with buyers enquiring for smaller volume of cargoes compared to before and sales performance this quarter has been dismal, a module seller said. Sales projections for the third quarter were equally bearish as module prices were expected to fall further with no market recovery in sight, the seller added.

The spread between TOPCon and Mono PERC prices has started to narrow. It is not surprising for Mono PERC prices to be slightly lower or similar to TOPCon prices as module makers are selling based on their Mono PERC inventory levels, a market source said. OPIS heard majority of discussions of Mono PERC at $0.090/W FOB China though a few sellers kept offers at $0.093-0.095/W FOB China.

In the Chinese market, the Ministry of Industry and Information Technology (MIIT) published proposals seeking public opinions on the “Regulatory Conditions for Photovoltaic Manufacturing Industry (2024 Edition)” and “Administrative Measures for Announcement of Photovoltaic Manufacturing Industry (2024 Edition)” on July 9.

One of the proposals was to raise the minimum capital ratio for new construction and expansion of photovoltaic manufacturing projects to 30% from 20% previously for wafer, cell and module production. Amongst the other proposals, MIIT guides photovoltaic enterprises to reduce photovoltaic manufacturing projects that simply expand production capacity.

One market veteran OPIS spoke to expressed skepticism that such measures would curtail production expansions and restore supply and demand balance in the Chinese market as capacity expansion plans are announced almost every day. Any positive impact from these measures would take at least two to three quarters from the implementation date for any improvements to be seen, the veteran added.

OPIS assessed the forward pricing curve for U.S. delivered duty-paid (DDP) mono PERC modules lower this week, indicating softer market values. Prices for PERC modules slated for Q4 delivery averaged $0.291/W ranging from $0.240-0.365/W on a DDP U.S. basis, while prices for 2025 delivery averaged $0.315-0.319/W ranging between $0.270/W and $0.365/W DDP U.S.

A producer noted that demand has weakened due to uncertainties surrounding U.S. tariff policies, while more competitively priced cargoes are emerging from Southeast Asian countries like Indonesia and Laos. The potential tariffs are expected to impact delivery schedules, and freight volatility remains a concern for buyers. Trade sources shared that TOPCon modules for spot loading from Indonesia and Laos are at $0.24/W to $0.28/W on a DDP U.S. basis.

In response to potential tariff complications, there has been an increase in Indian module shipments to the U.S., as buyers are cautious about purchasing from Southeast Asia. According to an industry source, May module shipments from India to the U.S. reached approximately 1 GW, accounting for around 20% of U.S. module imports. The source noted that India had previously represented a smaller share of U.S. module imports before May. Additionally, the source reported a 10-15% decline in Southeast Asian module imports in May compared to March and April.

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.

Despite Tropical Storm Beryl making landfall on the morning of Monday, July 8, relatively sunny conditions returned as the remnants of the system moved north-eastward, according to analysis using the Solcast API. Although southeast Texas was most affected by damaging winds and flooding, the cloud cover from the inclement weather system did see a large but temporary dip in solar generation potential across the state.

Solcast’s analysis of potential utility-scale solar generation in the ERCOT electricity grid region indicates that the cloud cover associated with Beryl significantly dampened solar generation on the morning of Monday the 8th. Cross-referencing with grid operator reports reveals that very little production went offline due to the storm, showing the resilience of Texas’ solar infrastructure.

By Tuesday, skies over Texas were relatively clear, with only isolated convective storms as Beryl moved northeast. Forecast thunderstorms for the coming weekend are likely to only put a mild dampener on solar generation in the ERCOT electricity region, with the southeast the most impacted, according to forecasts from the Solcast API.

When comparing the second week of July to previous years, overall ERCOT production this week is expected to be only 3% below typical generation levels. However, the southeast and Far East sub-regions of ERCOT were more significantly impacted by the cloud cover from Beryl, with generation more than 15% below average for the week, showing the localized nature of the storm’s impact on solar generation.

Tracking Beryl’s impact on daily irradiance shows a relatively small, well-structured storm on Sunday the 7th, just before landfall. As the storm moved northeast and rapidly weakened, the peak severe weather near its core diminished, but the spatial impact on irradiance increased as the system lost structure and spread out. This pattern shows how the storm’s dissipation affected solar generation potential across a broader area.

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.

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

A source familiar with the global polysilicon market noted that the spot polysilicon has been largely unsold for two months, with downgraded materials faring worse.

However, global polysilicon suppliers report no reduction in production so far, and customers who have a long-term agreement with the suppliers are still under some pressure and have taken goods at relatively stable prices. “Signing a long-term agreement is meant to protect the interests of both parties. Shifting all risks onto one party to completely avoid risks is a practice that lacks the spirit of a contract,” a source from one supplier commented.

According to a China-based source, a Chinese wafer manufacturer maintaining a low 30% operating rate domestically is sending wafer slicing equipment to Laos and may consider adding ingot capacity there in the future. This development suggests potential new sales channels for global polysilicon.

Due to reduced production rates of solar products in four Southeast Asian countries, the current ingot production requiring global polysilicon can only consume less than 1,500 MT of these materials per month, according to a source. The source also noted that the production capacity of newly constructed ingot plants outside of these countries is insufficient to fully stimulate demand for global polysilicon.

“We believe that in the coming years, ingot production capacity outside of China and the four Southeast Asian countries will flourish, introducing new factors that will influence global polysilicon prices,” stated a market observer. However, the source also noted that over the next two years, U.S. trade policy will remain a crucial determinant of global polysilicon price trends.

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

According to a market source, major polysilicon manufacturers halting price reductions have contributed to stabilizing mainstream market prices. The source added, “There’s a strong likelihood that polysilicon prices will stabilize at this current low point in the near future.”

According to an upstream source, a major manufacturer with strong financial backing and a high operating rate is actively ramping up its new annual polysilicon production capacity of 200,000 MT in Yunnan. Furthermore, their new 200,000 MT polysilicon plant in Inner Mongolia is currently under construction and expected to be operational by the fourth quarter of this year.

“However, we may expect some obstacles to the progress of this Inner Mongolia project due to the current market downturn,” a market veteran commented.

Another market observer noted that despite lower production costs for fluidized bed reactor (FBR) granular polysilicon, manufacturers are currently unable to maintain high operating rates due to the product’s market share constraints. “There are two FBR granular polysilicon manufacturers in China that engage in production and sales, with another manufacturer operating a research and development trial production line,” the source added.

A market participant concluded that based on the current downstream operating rates, an effective reduction in polysilicon inventory by the year’s end appears challenging. Further decreases in polysilicon production are expected in the second half of the year.

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.

The home solar industry experienced explosive growth through 2022, but along with that growth emerged misleading advertising, deceptive sales tactics, subpar outsourced installations, and predatory financing products. With this lack of transparency and accountability in industry practices, the solar industry has created a problem for itself: a crisis of trust.

The path back to growth in residential solar isn’t complicated, nor is it unique to solar. It’s all about building that trust. Here are five things we in the solar industry can do ASAP to reignite industry growth.

1. Put the consumer first. Respect their time, their needs and concerns, their finances, and the importance they place on their home. Speak truthfully and plainly, knowing that they are relying on us to give them accurate information and tailored recommendations for their home and circumstances. Our aim should be helping the homeowner make a good decision rather than getting them to sign a contract. Sometimes, the right decision for an individual homeowner is not to go solar, and that’s okay.
2. End the sales shenanigans. “Solar bros” have become the new “used car salesmen,” and the entire industry suffers for it. A great product nearly sells itself without the need for intense (and costly) sales. In our industry, a quality solar system installed at a great price doesn’t require hard selling. What we at EnergySage see is that the strongest and fastest-growing installers don’t sell hard. They design great systems at fair prices. They are respectful and responsive, but not pushy. They build trust, increase their close rates, and reinvest those would-be-huge sales commissions into improving their business.
3. Provide transparent pricing. Many homeowners assume the price of solar is “whatever the sales rep can get you to say yes to” just like car sales. They enter the conversation already suspicious. What does that do? At best, it increases sales touches, adds uncomfortable negotiations, and slows down the sales cycle. At worst, it causes the homeowner to completely walk away from solar. They lose out on all the benefits of solar. They do not become an evangelist for solar. The industry doesn’t grow. Transparent and fair pricing doesn’t mean the lowest price. In fact, on EnergySage, the majority of shoppers do not choose the installer that quotes the lowest price. They choose their installer based on the overall quality and value of the proposal (of which price is one component) and the installer’s reputation and responsiveness.
4. Create simpler contracts. We all hate lengthy legal documents. The longer a solar contract is, the more apprehensive a homeowner will be. At EnergySage, shoppers often ask our independent Energy Advisors to help them understand a complicated document from their installer. If your contract and proposal necessitate review from a lawyer or an independent advisor, you are likely losing sales. Simplicity wins.
5. Better (normal) financing options. Recently the Minnesota Attorney General sued four of the largest solar loan providers for fraud. While the case is yet to play out, it’s obvious to anyone who works in the solar industry that solar financing products are strange. Dealer fees, buying down interest rates, leases, and PPAs are too much to ask the average homeowner to fully understand. What homeowners do understand are mortgages, home equity loans, HELOCs, and personal loans. It’s important for consumers and installers alike to understand that most solar loans are paid off in 5-7 years. That means solar loans with high upfront fees in exchange for lower long-term interest rates typically don’t make sense for homeowners. Kudos to companies like Climate First Bank and Atmos Financial who are innovating to create more straightforward solar loan products.

The land grab in solar is over. Fly-by-night installers have started disappearing. On the other hand, installers that provide a great product and great service at a great price are continuing to grow. But the only way to truly reignite industry growth is for the industry to improve its overall reputation, and that means change. We can change the industry ourselves, or we can wait for increased regulation and more lawsuits to change it for us. The former sounds much better. 

Warren Buffet famously said, “It takes 20 years to build a reputation and five minutes to ruin it.” There are great installers with great reputations out there (we work with hundreds of them), but the residential solar industry as a whole has some reputation repair to do, and the best time to start is now.

Solar should be every homeowner’s cheat code. Solar energy can revolutionize our homes and communities by delivering huge energy and financial savings, reducing our carbon footprint, increasing individual and grid resiliency, and more. But none of that matters if we can’t unlock mass adoption, and that will require prioritizing consumer protection and transparency.

Josh Levine is the vice president of marketing at EnergySage, the leading marketplace for clean home energy solutions. With previous experiences at Google, Procter & Gamble, and as an officer in the U.S. Army, he is responsible for ensuring EnergySage maintains its consumer-first values in everything the company does.

From ESS News

The rapid expansion of renewable energy sources, such as solar and wind, presents opportunities and challenges. While these sources drastically reduce carbon emissions, they also introduce variability and intermittency into the power grid. We must address this imbalance and ensure the stability and reliability of our energy systems.

However, it is crucial that the imbalance that renewable energy creates is not seen as an individual challenge but as a collective responsibility that requires collaboration between grid operators and renewable energy producers. As we face these unprecedented challenges, the need for flexible assets like batteries becomes more pronounced.

For now and in the foreseeable future, batteries offer a crucial means of managing fluctuations in renewable energy production. Whether providing short-term frequency regulation or storing excess energy for later use, batteries can play a vital role in balancing supply and demand on the grid.

As the prices for electricity and ancillary services vary, the value of a battery increases. Our view is that we have only seen the tip of the iceberg concerning the hourly variations in prices. As the cost of a battery gradually decreases, and it generates multiple benefits, such as behind the meter in hybrid plants, it is something to consider for renewable energy producers.

Through the lens of a grid operator, we must prepare for the expected increase of imbalances occurring from forecasting errors. This includes when selling renewable energy in the day-ahead and intra-day electricity markets. We foresee the need for balancing energy to increase proportionally with the capacity of renewables connected to the grid. Hence, everyone needs to provide as much flexibility as possible to ensure the cost-effective balancing of a fully renewable energy system. This is particularly true in Denmark, as the main providers of flexibility are slowly phased out, namely the central and decentral combined heat and power plants.

Hence, new technologies and renewable energy companies will be crucial in maintaining system stability. Collaboration in the balancing market is essential to ensure a smooth transition towards a renewable energy-driven future.

If we, as renewable energy producers, bring large amounts of renewable energy production online, we must take responsibility for how it impacts the grid. This means planning projects that align with the objectives of the grid operators.

Looking at the future of the energy system, it should be a shared goal to design markets that provide economic incentives to support balancing the system. No matter what solutions each market finds, increased flexibility and joint responsibility look to be key elements. Producers and operators will have to work together to achieve market dynamics that make the system work for all participants.

As an example, Better Energy is undertaking its first battery project at one of its Danish solar parks, where a 10 MW lithium-ion system will be installed by the end of 2024. This presents an opportunity for us to develop strategies based on Energinet’s need for system flexibility and an energy system based primarily on renewables.

Technology aside, we can’t successfully transition to renewable energy without a strong understanding and cooperation with the grid operators. Our organisations have previously collaborated to certify a solar park to provide frequency services. This is an example of the collaboration and understanding needed between renewable energy producers and grid operators to achieve a stable and reliable power grid.

As the country with the most intermittent renewable electricity production relative to the electricity consumption in the world, Denmark and Energinet want to punch above its weight and demonstrate that it is possible to balance a fully renewable system cost-effectively. We try to foster innovation and new solutions and have a history of strong collaboration with market parties.

From Better Energy’s perspective, Denmark is fortunate to have such progressive grid operators who are committed to transitioning away from fossil fuels and building an energy system that will sustain us for years to come. We hope this approach will serve as an example for surrounding countries that are in the midst of the energy transition.

About the authors:

Viggo Aavang is Senior Vice President of Power Markets at Better Energy, a renewable energy company that develops, constructs and operates renewable energy parks in Northern Europe.  He has over 20 years of experience in European power markets and is committed to building a flexible energy system based on renewables.

Thomas Dalgas Fechtenburg is Senior Manager, Ancillary Services at Energinet, the Danish transmission grid system operator. He has over eight years of experience at Energinet and is deeply committed and involved in developing solutions that will allow Denmark to balance the renewable system of the future.

From pv magazine 6/24

Curtailment is becoming an increasingly important issue for the power sector, particularly as the share of solar and other intermittent-generation renewable energy sources continues to grow.

At small volumes, curtailment rarely poses a major issue for solar plant operators, or for the financial viability of projects. This is mainly because most jurisdictions continue to offer “take-or-pay” contracts that shelter PV project owners, either in part or in full, from revenue losses associated with curtailed electricity output.

In larger volumes, however, curtailment has the potential to undermine the economics of new solar projects, significantly increasing investment risk. Unlike in the past, when solar projects were financed via long-term contracts in the context of auctions or feed-in tariffs, many sites are now being financed either via bilateral power purchase agreements (PPAs) or on a merchant basis, which involves selling energy on the open market. Uncertainty about the volume of electricity that could be curtailed directly increases the cost of capital for PV projects and, in turn, puts upward pressure on the cost of solar. Furthermore, a perception that solar output is being “wasted” could gradually erode public support for further PV deployment, particularly if the curtailed volumes grow substantially.

Deep cuts

Data from a selection of markets show that curtailment is on the rise. In Chile, the curtailment of solar has increased significantly in recent years, affecting 1.4 TWh of output in 2022 – roughly 1.8% of annual electricity demand – and nearly 800 GWh in the first five months of 2023. In Cyprus, PV curtailment has grown from just over 3% of generation in 2022 to more than 13% in 2023. In parts of Australia, curtailment has grown from roughly 4%, in the first quarter of 2022, to more than 7% in the opening three months of 2023, with certain days posting curtailment levels nearing 20% of total available PV output. In parts of the United States, curtailment is also on the rise: in Texas, 9% of the output from utility scale solar was curtailed in 2022. In California, more than 3% was curtailed in the same year. In Germany, the curtailment of solar amounted to almost 2% of total PV output in 2022.

At its core, curtailment is a symptom of an insufficiently flexible power system. Fortunately, experience shows that curtailment can be avoided or significantly reduced through policy. Particularly during the early phases of PV penetration – when up to 10% of power generation comes from solar – there are often other, lower-cost flexibility options available.

At this early stage, the toolkit includes measures such as reducing the must-run hours of fossil-fuel-based power plants; increasing the flexibility of other power generation sources, such as hydropower or biomass; moving toward economic dispatch; introducing intra-day electricity markets; and improving both demand and solar output forecasting.

Broader toolkit

At higher shares of solar generation, a broader toolkit is starting to emerge. Measures include increasing the flexibility and responsiveness of power demand, introducing combined procurement of solar-plus-storage systems, encouraging new business models such as virtual power plants and aggregators, introducing more dynamic electricity pricing, including locational pricing, and making greater use of surplus electricity in the transport and heating and cooling sectors.

Basic economics are also helping as periods of electricity oversupply lead to lower prices, which in turn makes it more attractive to consume electricity. In South Australia, the power system experiences sub-zero electricity prices almost 60% of the time between roughly 11:30 a.m. and 2 p.m. With the continued growth of solar, and without a significant scale-up of demand-side flexibility, markets such as South Australia will start facing repeated periods where daytime electricity prices are permanently negative between 10 a.m. and 4 p.m.

In response, the government and power utilities have started implementing measures to encourage greater flexibility, including through demand-response-enabled pool heaters and air conditioning units, variable electricity pricing, and flexible electric vehicle charging.

Not all negative

From a power system standpoint, curtailment should not be thought of purely in negative terms. It can also contribute to power system flexibility in a manner that can be activated relatively easily to maintain system stability.

In fact, it may be less expensive for solar project operators – as well as for the system as a whole – to curtail PV output occasionally than it would be to build out large-scale energy storage or power grids to ensure that solar output is never curtailed.

With the share of solar rising in virtually every country around the world, it is time for a wider debate about curtailment, how to bind it contractually, and how curtailment itself stacks up both in technical and economic terms against other ways of balancing energy systems. As the world progresses toward its second terawatt of installed solar generation capacity, and beyond, this debate is only going to grow in urgency and importance.

About the authors: Toby Couture is the founder and director of E3 Analytics, an independent renewable energy consultancy in Berlin, Germany. He has 15 years’ experience in the sector and has advised dozens of national and state governments throughout the world on renewable energy policy, strategy, and finance.

David Jacobs is the managing director and founder of International Energy Transition GmbH (IET). He has 20 years’ experience in energy policy design, authoring more than 100 publications. He has advised policymakers in more than 40 countries.

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. 

From pv magazine 6/24

Although an accurate assessment of solar resources is key to ensuring the reliability of an energy yield assessment, most studies rely exclusively on satellite irradiation data. Solar developers rarely dedicate resources to installing a weather station to obtain ground-measured data before PV project construction, mainly because of the significant costs involved. Operating a weather station for a year costs between €40,000 ($43,000) and €60,000. A satellite dataset costs several hundred euros.

The development of bifacial modules has complicated the assessment of available solar resources. Irradiation arriving at the rear side of bifacial modules is mainly determined by albedo, which is the ratio between downward irradiation reaching the ground and the upwelling irradiation reflected by it. As with other data, such as global or diffuse irradiation, albedo can be obtained from satellite imagery. Leading data providers also offer this information. Albedo is more difficult to assess than downward irradiation, as it is influenced mainly by the nature of soil. Satellite data resolution is, at best, around 1 km² and the nature of soil, and hence albedo, can significantly vary over such a relatively small area. Albedo will also vary during a day, depending on factors such as the position of the sun, the season, and the weather. A slightly erroneous albedo value can easily cause a 0.5% impact in a yield assessment that could affect project valuations by significant amounts of money.

These factors lead us to the conclusion that albedo should be measured. Nevertheless, the cost of a one-year campaign is still a “no-go” for most developers. Alternatively, some service providers propose short-term measurement campaigns where the albedo is measured on site for one or several days. This measurement is then used to calibrate satellite albedo data.

Short-term benefits

Since Everoze is often asked to use data corrected with short-term albedo measurements, we wanted to forge our own opinion on the benefits of such short-term measurements. We used publicly available, quality-checked weather station measurements, including global irradiation and albedo figures, and analyzed the effect of calibrating this data with short-term albedo measurements from one-day and seven-day campaigns.

We used data from the Surface Radiation Budget Network (SURFRAD) from seven sites in the United States. High-resolution data have been extracted for six years, from 2017 to 2022, and used to calculate a monthly reference albedo for each of those sites, averaged over the six years. For instance, the reference albedo for January was the average of all January albedo values from 2017 to 2022. We also downloaded satellite albedo data from the Prospect tool of solar irradiance data company SolarGIS for the seven locations.

Everoze applied several quality checks to the SURFRAD data, which led to the elimination of a negligible number of days over the six-year period. We then used the albedo of every single day as one-day campaigns and rolling seven-day periods as weekly campaigns, correcting all the satellite data based on these campaigns. Finally, with solar design tool PVsyst, we simulated a theoretical single-axis tracking, bifacial PV asset and ran yield scenarios featuring the six-year average SURFRAD albedo, raw satellite albedo, and satellite albedo.

We compared the yields. The measurement campaign was considered beneficial if the difference between SURFRAD data and the corrected albedo was lower than the difference between SURFRAD and the raw satellite albedo. The figure below illustrates the results for one-day and seven-day campaigns for each of the seven project sites.

Value for money

The results showed one-day campaigns should be discarded because they are not beneficial in most cases, in particular during the winter. Seven-day campaigns are mostly beneficial in the summertime. The author noted that data from other regions may lead to different conclusions. Other factors such as location, height, calibration, and the cleaning frequency of the albedometer should be considered with care. Everoze recommends making the investment to cover a full year of measurements, rather than only a few days. It may be costly in the short term but worth it over a project lifetime.

About the author: Stefan Mau is an electrical engineer and has been working in solar since 1999, including in R&D, testing and certification, measurement, and consultancy services in Spain, Germany, and Austria. Before joining Everoze, he was global contact for operational services in PV plants at DNV GL. At Everoze, he supports commercial PV services such as due diligence, bankability, and energy assessments and training. He is part of the Spanish standardization committee for PV modules and holds one patent.

From pv magazine Global

About the author: Martin Schachinger has studied electrical engineering and has been active in the field of photovoltaics and renewable energy for almost 30 years. In 2004, he set up 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.

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. 

From pv magazine Global

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

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

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

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

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

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

From pv magazine Global

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

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

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

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

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

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

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

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

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

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

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

From pv magazine Global

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

Life Cycle Assessment: A Comprehensive Overview

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

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

Evaluating PV Module Technologies

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

Key Findings from the Fact Sheet

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

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

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

Conclusion

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

Please download the Fact Sheet here.

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

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

From pv magazine Global

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

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

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

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

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

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

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

From pv magazine 6/24

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

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

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

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

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

Location and equipment

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

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

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

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

Matter of standards

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

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

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

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

Managing differences

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

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

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

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

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

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

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

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

Shelf warmers

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

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

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

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

Project sales

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

From pv magazine 6/24

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

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

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

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

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

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

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

From pv magazine 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.

From pv magazine Global

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

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

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

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

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

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

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

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

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

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. 

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Solar import tariffs aim to level the playing field by addressing the market price disparities of solar power hardware originating from China, while supporting domestic manufacturers. This strategy is part of the United States government’s broader efforts to protect national security and combat climate change.

Recently, these tariffs have ranged from symbolic warning shots to upward price adjustments that might increase the cost of solar modules and energy storage. Additional looming tariffs on solar panels, aluminum, steel, and other materials could further escalate industry costs.

Canadian Solar is a global company whose products bear multiple import tariffs. As well, in response to the Inflation Reduction Act (IRA), Canadian Solar plans to begin manufacturing solar cells in Indiana and assembling modules in Texas.

During a case initiated by the global Hanwha Q Cell at the U.S. International Trade Commission, Jonathan Stoel, a partner at Hogan Lovells LLP and counsel for Canadian Solar’s U.S. Module Manufacturing Corporation, made a statement they also provided to pv magazine USA. He argued that the case was “brought entirely on false pretenses and based on fundamentally erroneous predicates.”

Stoel outlined the perceived inaccuracies:

• The assertion by other petitioners that 36 GW of solar panels are at stake in this ruling is a significant overestimation, likely intentional.
• The claim that the majority of the solar manufacturing industry supports the tariffs is misleading. In reality, only three companies – major one though – have advocated for the tariffs. It was noted that most companies planning to assemble solar panels in the U.S., due to the IRA incentives, oppose the import tariffs on solar cells because they rely on importing these components.
• Solar cells and solar modules are distinct technologies. Stoel cited evidence that Hanwha’s Q Cell operates two separate facilities for manufacturing solar cells, while also importing solar modules. It is important to note, as pv magazine USA adds, that the nation’s largest solar manufacturer, First Solar, integrates the production of solar cells and modules in a single process. However, this case specifically addresses crystalline solar cells, which First Solar does not produce.
• Stoel emphasized that Hanwha’s expansion in Georgia was primarily motivated by government incentives, which is the very thing that this case seems to push back against.

In response to the points raised, Stoel urged the court to recognize several key aspects of the case: (1) it was filed on dubious grounds; (2) major manufacturers, not a majority, are opposed to imports; (3) modules and cells are distinct products; (4) the import volumes are far less significant than suggested and have not caused material harm; (5) adverse price effects have not been observed; (6) the court should consider the financial health and growth of the industry, spurred by incentives introduced by the IRA; (7) many US companies involved, including Hanwha’s Q Cell which initiated the case, have substantial international connections.

Despite the claims regarding the absence of adverse price effects, the cost of solar cells and modules in the United States has dramatically decreased. This reduction is due to a collapse in Chinese polysilicon pricing and a rapid increase in manufacturing capacity. Since even Chinese manufacturers, such as Longi, have acknowledged that this surge in capacity is negatively affecting their business, it can be fairly inferred that competing companies might perceive these developments as disadvantageous.

Ultimately, while the tariffs are presented as protective measures for domestic industries, their effectiveness is debatable. The global dynamics of the solar market and strategic responses by manufacturers suggest that these measures might serve more as diplomatic signaling than impactful economic barriers. Historically speaking, as noted in the above chart, tariffs alone haven’t shown to grow the U.S. solar manufacturing base – however – the IRA did.

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

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

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

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

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

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

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

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

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).