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Global PV installations are on track to reach 638 GW in 2026, according to analysis from solar and storage technical advisory firm Intertek CEA.
The company’s PV Supply, Technology and Policy Report for Q2 2026 predicts a decline on last year’s installation figures before resuming growth to 2030.
It says this year’s downturn is driven entirely by China, which is facing market stagnation, while most other regions of the world are set to see either flat or accelerated growth. 
The report adds that structural oversupply is “severe and persistent” across the solar supply chain, with manufacturing capacity across all stages exceeding projected 2026 demand by wide margins.
Polysilicon capacity stands at approximately 2,034 GW against 638 GW of installations, according to figures from the report, while module capacity of around 1,908 GW leaves an excess of more than 1.2 TW.
Intertek CEA’s PV Price Forecasting Report for Q2 2026 adds that Chinese module prices are set to continuing rising in 2026 through to 2027, as suppliers “push for margin expansion and material cost passthrough.”
It also says US module prices wil remain elevated as the market “awaits clarity on the tariff structure likely to emerge from the polysilicon Section 232 investigation”, while Indian module pricing through 2026 and 2027 will stay exposed to Chinese input costs.
From 2028 onwards, Intertek CEA is expecting prices to decline, citing market maturity and low but stable margins.
The report adds that regionally-integrated production costs range from under $0.12/W to over $0.37/W, with US manufacturing subsidies narrowing the US-to-non-China cost gap to just $0.01 to $0.03/W.
Indian cell and module assembly, as well as module assembly in the southeast Asian market, is predicted to come within $0.01 to $0.03/W of Chinese prices “in time”, the report continues, but EU module assembly is forecast not to close its price gap with other markets.
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Monday, October 26, 2026
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Plug-in solar bill awaits governor’s signature in California  cbs8.com
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Global horizontal irradiance across Europe averaged 5% above the 2007–2025 norm in August 2026, extending the elevated solar resource recorded during June and July, according to analysis using the Solcast API. Nearly three quarters of the continent received above-average irradiance as persistent high pressure limited cloud formation and storm development. Much of southern England experienced Europe’s strongest positive anomalies, reaching more than 20% above average, before a change in weather patterns brought cooler and cloudier conditions to parts of western Europe during the second half of the month.
High pressure remained the main influence on Europe’s solar resource for much of August. Sinking air within the persistent system stabilised atmospheric conditions, limiting cloud formation and supporting extended periods of clear sky. Although August is typically Europe’s second-sunniest month, irradiance reached more than 20% above the seasonal norm in some regions. This marked a third consecutive month of elevated solar resource across much of western and central Europe, while London’s cumulative GHI reached a record high for this point in the year.
The unusually sunny conditions coincided with exceptional drought across parts of Europe. Southern England experienced 62 consecutive dry days through the middle of August, easily breaking the previous record of 51 days. According to the European Commission’s Joint Research Centre, critically low levels on the Rhine and Danube disrupted hydropower and nuclear generation, increasing reliance on other generation sources, including solar.
In Birmingham, the prolonged lack of rainfall provided few opportunities for natural module cleaning, allowing modelled soiling losses to accumulate before rain returned in mid-August.
The prolonged high-pressure pattern began to break down during the second half of August. As the system weakened and shifted eastward, a cold front arrived from the Atlantic and temperatures fell by more than 15 C across parts of western Europe after weeks of persistent heat and dry weather. Increasing cloud and rainfall reduced the earlier irradiance surplus as the front moved into France and Germany.
The late-month change had an uneven effect on Europe’s irradiance. Central and eastern regions retained more of their earlier surplus, while parts of southwestern Europe finished closer to or below their long-term average.
Porto’s daily irradiance profiles provide a closer view of the changing conditions in the southwest. Early-month profiles were generally more consistent, while several days around and after mid-month recorded pronounced daytime reductions.
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 350 GW of solar assets globally.
The views and opinions expressed in this article are the author’s own, and do not necessarily reflect those held by pv magazine.
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pv magazine: Mr. Brown, the Chinese government has successfully reduced excess capacity in the past, particularly in coal and steel from around 2015, as well as in sectors such as cement, glass, aluminum and shipbuilding. What lessons from those restructuring efforts can be applied to today’s PV manufacturing industry?
Alexander Brown: One lesson is that when the Chinese government sees a need to stimulate growth in a certain sector, it is very capable of doing so. We saw that with sectors related to construction in the 2010s, and we have seen it more recently with green technologies as China has focused increasingly on its decarbonization agenda.
But in many cases, this leads to overshooting and overinvestment. There is a recurring challenge for Chinese policymakers in finding the right balance when they seek to boost particular industries.
What is different in solar PV is the range of options available to the government when it subsequently tries to rein in excess capacity. The clearest difference between PV and sectors such as cement, glass, aluminum and shipbuilding is company ownership. Solar PV is dominated by private firms, whereas state-owned enterprises were and still are dominant in many of those other industries. That makes coordination somewhat easier when companies are state-owned.
There has been considerable difficulty coordinating companies in the PV industry. There is broad agreement that there is a problem. Companies acknowledge the need to prevent prices from falling further and to stop overinvestment, but individually they still have incentives to expand. Their actions therefore often do not follow their words.
Is technological innovation another reason why consolidation is more difficult in PV than in mature industries such as steel, cement or glass?
Yes. The rapid pace of technological development definitely plays a role. Equipment and technology can be updated every two to three years. That is very different from industries such as cement and glass, where the technologies are much more established.
Demand has also been increasing strongly. China’s production capacity currently far exceeds global demand, but global demand has grown substantially in recent years, as have China’s exports. Between 2019 and 2023, China’s top five producers of solar modules consistently generated healthy profit margins in the range of 8 to 12 percent on average. So even from the perspective of a normal market economy, there was some logic behind these very large increases in manufacturing capacity. Ultimately, however, they have resulted in a severe mismatch between supply and demand.
How important is geopolitics in sustaining or exacerbating China’s PV overcapacity? How are trade barriers and industrial policies in the United States, Europe, India and elsewhere affecting Chinese manufacturers’ investment decisions?
Geopolitics is an important factor in China’s solar sector. The crisis the industry faced in the early 2010s following changes to trade barriers in Europe and elsewhere demonstrated how dependent the sector was on exports. It is less dependent on exports today, but they remain important for China’s leading solar companies.
It is also clear that Chinese manufacturers are sensitive to regulatory changes overseas. We have seen a number of production facilities built in Southeast Asia in an attempt to secure access to foreign markets, particularly as the United States has introduced measures aimed at reducing its reliance on solar products coming directly from China.
However, I wouldn’t say these measures have been extremely damaging to the industry so far. China has continued to increase solar module exports in recent years, and there are questions about how effective US tariff barriers have been.
If more countries impose higher trade barriers, however, that could put considerable pressure on the sector. Growth in solar demand appears to be slowing in China and elsewhere. If exports become less available as an outlet for excess production, that will aggravate the situation.
So, geopolitics matters, but it is not the fundamental cause of the current problem?
That’s right. Geopolitics plays a role in how solar companies decide where to invest and how much capacity to build, but fundamentally the domestic market is more important for these firms.
Compared with the solar downturn of the early 2010s, I would say geopolitics is less important today. Back then, the Chinese government responded by significantly increasing domestic demand to support its domestic solar industry. I don’t think we’re going to see that sort of response this time.
The present oversupply cycle became increasingly visible in 2023 and acute by early 2024. More than two years later, excess capacity remains substantial and permanent capacity exits appear limited. Is the adjustment taking unusually long? How long can manufacturers sustain heavy financial losses?
It is not unusual for these adjustments to take quite a long time. If we look at consolidation in the steel sector, measures were taken to consolidate companies, but a lot of capacity remained in the system and was only slowly removed.
In solar, however, the process is definitely taking longer than hoped. That’s partly because of the difficulty of coordinating the main actors and because the market is so fragmented.
That is also related to the technology itself. Solar is somewhat more commoditized than products such as wind turbines or electric vehicles, making it easier for companies to enter the sector. Older technology can also remain in use, with slightly outdated products sold cheaply around the world. Those mechanisms allow capacity to remain in the system.
The profitability of China’s leading companies has declined dramatically in 2024 and 2025. We looked at the top five Chinese firms and found that their aggregate profit margin last year was minus 11%, which is extremely poor. Pressure on the industry to find a solution will therefore continue to grow. If it doesn’t happen this year, then probably by next year some kind of arrangement will have to be reached.
We’ve seen other sectors handle this more successfully. In wind, for example, leading players have come together to revise tendering practices so that tenders are not focused solely on obtaining the lowest price. Similar attempts to reach agreements in solar have failed so far, but the pressure to make such efforts succeed will increase.
During the previous PV consolidation phase, from roughly 2011 to 2014, numerous companies became insolvent. We have not seen comparable failures among today’s largest manufacturers. Why are the major players able to remain afloat despite prolonged losses?
I think it’s very unlikely that we’ll see the major players fail. To some extent, they have diversified businesses. Many are active in different parts of the solar supply chain, and they generate revenue not only from manufacturing products but also from activities such as project development.
Local governments also have a very strong interest in keeping these companies afloat. They can provide different forms of support, including tax incentives, loans and equity investments. These companies provide local tax revenue and jobs, and they remain extremely competitive in international markets. For those reasons, I think it is very unlikely that the major players will simply be allowed to go under.
Beijing has introduced a series of measures since 2024, including efficiency and energy-consumption requirements, tighter investment rules and measures related to pricing. Are these measures sufficient to accelerate consolidation?
It is interesting that since mid-2024 we have seen measure after measure introduced in an attempt to solve the problem, and clearly they haven’t worked so far.
But I think the cumulative effect of these measures will eventually have an impact. New rules around energy pricing, in particular, look likely to affect solar demand in China. It will take time, but if domestic demand slows significantly, companies will have to respond.
They have already started responding by cutting costs and laying off workers over the past couple of years. If the market is no longer growing, it will become very difficult for companies to continue investing in new capacity. At the same time, progressively higher standards will gradually remove some capacity from the market.
So, I expect it to be a relatively slow process, but I think these policies will be successful to a degree. It is largely a matter of time.
What additional measures could the Chinese government take if the current policies prove insufficient?
One possibility would be to revise tendering standards so that tenders take into account factors such as quality and longer-term considerations rather than simply the immediate lowest price. We’ve seen something similar in the wind sector. That would require agreement between manufacturers as well as energy project developers.
Beyond that, it may require more direct intervention by the central government. Local governments will not willingly let their companies fail. But the National Development and Reform Commission could essentially decide that the industry only needs a certain number of major players and that outdated manufacturers should be cleared from the market. It could then instruct local governments not to continue providing lifelines to those companies.
I think that would work. But it would require very clear instructions and direct central-government intervention, and that goes against the way China’s industrial policy has generally operated. China has been very successful in using competition between local governments to build up industries, which makes policymakers reluctant to move away from that tried-and-tested model.
Could significant overcapacity ultimately become a permanent structural feature of the solar manufacturing industry rather than something that disappears at the end of each cycle?
I think the fact that the technology is advancing so rapidly makes it difficult to avoid a certain amount of overcapacity. Companies are incentivized to upgrade their technology frequently. Unless older production capacity is forced out through progressively higher standards, that capacity can remain in the system.
And even if older technology is no longer used in China, products from those lines can potentially be exported. So I think bringing excess capacity down significantly will remain challenging. In rapidly developing technology industries like this, some degree of overcapacity is difficult to avoid.
Should we expect regular boom-and-bust cycles in PV manufacturing? Could the current downturn last seven or eight years, or is the timing fundamentally unpredictable?
The boom-and-bust cycle will be determined to a large degree by the emphasis governments place on the energy transition. Solar is a market that is projected to grow significantly over the coming decades. The question is when that growth accelerates and when it slows.
At the moment, we’re in a phase of slowing growth and a bust cycle. My expectation is that this will lead to some reduction in overcapacity over the next couple of years.
After that, we’ll have to see when the industry identifies renewed opportunities and begins making very significant investments again. That would create another boom cycle. Much will depend on policy decisions in the major markets and on whether governments choose to accelerate or slow demand for solar technology.
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Monday, October 26, 2026
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Tuesday, September 15, 2026
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pv magazine USA hosts its multi-day virtual event on U.S. solar and energy storage, covering domestic manufacturing, distributed energy and the growing role of solar-plus-storage in meeting AI-driven power demand.
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Its edge increased month by month as the weather turned hotter and sunlight intensified.
Photo Credit: Nanjing University
A China-led research team may have moved one of solar power’s most promising next-generation materials much closer to everyday use.
On a working solar farm, a 1-megawatt perovskite installation generated more electricity than a silicon competitor, and its lead widened in warmer weather.
As the South China Morning Post reported, a China- and Canada-based team led by Nanjing University developed a highly stable coating for perovskite solar modules, a lightweight, ultra-thin material widely considered a leading alternative to silicon.
They published the breakthrough results in Nature.
The development was not just about efficiency but durability at a larger scale, SCMP noted. The team said its coating can repair tiny defects in perovskite that would otherwise waste electricity, helping the material stay stable enough for commercial use.
Commercial readiness depends on surviving harsh conditions as well as converting sunlight efficiently, per the outlet. 
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In this case, a perovskite module about the size of a dining table delivered 158.4 watts at 22% efficiency while enduring the heat, humidity, and temperature variation expected in real-world use, which the researchers said set a record for the technology at this scale.
The clearest test came at the solar farm itself, where the group placed a 1-megawatt perovskite system on the same site as a 3.5-megawatt silicon facility.
During March, April, and May, the perovskite setup generated more electricity than the silicon one when measured against the same installed capacity, SCMP reported.
Its edge increased month by month as the weather turned hotter and sunlight intensified. The separation was 3.4% in March, 3.8% in April, and 5.8% in May, according to the outlet.
“Our findings establish a new benchmark for manufacturable perovskite photovoltaics, where processability, durability, and efficiency are no longer mutually exclusive but are engineered from the outset,” the authors wrote in the study.
Perovskite has drawn significant attention in the solar industry because it can be made into a very thin film and manufactured at a lower cost than silicon.
That opens the door to lighter solar panels and more flexible applications, including on rooftops, building surfaces, and other places where heavy panels can be hard to install.
Panels that perform better in hot weather could be especially valuable during periods when air-conditioning demand pushes power bills higher.
Generating more electricity from sunlight can reduce reliance on polluting energy sources, but the biggest challenge for perovskite has long been stability.
While lab results have looked promising for years, scaling the technology into larger modules that can survive outdoor conditions has proved difficult. 
The researchers are moving perovskite from a promising lab material toward equipment capable of operating at utility scale, as SCMP detailed.
A large-module record alone does not answer commercial questions, so the solar-farm trial was important. Together, those results show the technology can handle the operating conditions that buyers, builders, and power companies watch closely.
Lighter, high-performing solar panels could expand access for homeowners and apartment dwellers whose barriers include weight, heat, or installation costs.
If those gains continue over longer testing periods, perovskite could become a practical way for homes, businesses, and utilities to produce more low-cost electricity exactly when hot, bright conditions drive power demand highest.
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An expansion may require a new inverter, utility approval, and an updated system design.
Photo Credit: iStock
A solar array that once matched a household’s needs can come up short after additions to the home.
One homeowner’s experience, shared on the r/SolarDIY subreddit, shows how electrifying more of everyday life can turn a formerly sufficient system into a candidate for expansion.
In the post, the homeowner explained that the household’s power needed an upgrade after they bought an electric vehicle in 2019 and installed central air in 2020.
The home’s 5.2-kilowatt, ground-mounted, grid-connected system, installed in 2015, had been enough to cover all electricity use.
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Summer demand was 55 kilowatt-hours per day, while the array supplied only 30-36 kWh. “For the first several years, it provided 100% of our daily electricity plus a bit extra in the summer months,” the homeowner wrote.
They wanted to know of any pitfalls they might encounter when adding capacity.
Going solar is one of the best ways to save money on home energy, especially for households expecting their electric use to grow over time. If you’re considering a new setup or an expansion, EnergySage can help you get free solar installation estimates and compare quotes.
The original poster conceded any expansion would likely include replacing their aging 6,000-watt SunPower inverter. Commenters agreed, and the homeowner said they had enough land for a second set of roughly 20 panels. Their goal was to add 6-8 kW.
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“You can have two separate systems, too,” one user stated. “One to power the AC and EV and the other to do the rest.”
Other commenters pointed to revisiting conductor sizes and protection devices as well as looping in the power company.
Solar is often only the first step in electrifying a home. Once drivers begin charging an EV at home or families install AC for comfort and safety during hot weather, electricity demand can rise.
For many households, a solar system is not just a one-time purchase. It can be part of an evolving plan. Ground-mounted setups may offer flexibility.
💡Go deep on the latest news and trends shaping the residential solar landscape
For homeowners in a similar position, the next step is usually to review energy use, future plans, and equipment limits before adding panels. An expansion may require a new inverter, utility approval, and an updated system design.
For shoppers, EnergySage’s free services can make that process easier to navigate. With EnergySage’s help, the average person can save up to $10,000 on a solar purchase and installation. 
EnergySage’s solar map shows the average cost of a home solar panel system by state as well as details on incentives. Together, these resources can help readers get the best price for rooftop solar panels and access available incentives.
Adding battery storage to a solar setup is one of the best ways to protect your home during outages, save money on energy, and go off-grid. Batteries can also store excess solar production for later use, giving households more control over when and how they use the power they generate. Readers can explore EnergySage for information about home battery storage options, including competitive installation estimates.
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The photovoltaic solar panels gleam golden in the sunlight in Songxi, Fujian Province, southeast China, April 13, 2021. /CFP
Editor’s note: Liu Baocheng, a special commentator for CGTN, is the Dean of the Center for International Business Ethics at the University of International Business and Economics. The article reflects the authors’ opinions and not necessarily the views of CGTN.
The Science article “China’s Solar Expansion Policy Reduces Bird Diversity” makes an important contribution to the debate over renewable-energy development. Using a panel of 2,344 Chinese counties from 2014 to 2023, the authors report that stronger policies promoting photovoltaic (PV) expansion are associated with lower local bird diversity. A one-standard-deviation increase in policy intensity is estimated to reduce the bird biodiversity index by about 2.1%, with substantially stronger effects in wealthier and non-desert regions. The paper links much of this effect to land-use change: Cropland and grassland are converted into developed land, vegetation becomes more homogeneous, and bird diversity declines.
These findings deserve serious attention, not because they establish that solar power is environmentally undesirable, but because they expose a common blind spot in conventional environmental thinking. The energy transition is often discussed through a binary framework in which fossil fuels are classified as environmentally harmful while renewable energy is presumed to be environmentally benign. The paper shows why that distinction is too crude. Low-carbon technologies can still carry land, habitat, mineral, water and infrastructure costs, and those costs vary largely according to where and how a technology is deployed.
The paper is therefore most useful when read not as an indictment of solar energy, but as an argument for more intelligent environmental planning. Its evidence suggests that the key question is not simply whether China should continue expanding PV capacity, but how that expansion can be spatially organized so that decarbonization, energy security and economic development are achieved with the lowest avoidable ecological cost.
The paper’s most important contribution: beyond green labels
The paper’s discussion of “inferior greening” is especially illuminating. The authors find that PV expansion can increase leaf area while reducing vegetation diversity and bird diversity. That result is a useful warning against equating visible greenness with ecological quality. A landscape can become greener in a narrow physical sense while becoming poorer in habitat variety, species composition and ecological function. Environmental assessment therefore cannot rely on a single indicator such as vegetation coverage, canopy density or carbon absorption. More green is not necessarily better ecology.
This insight reaches beyond photovoltaic development. Afforestation, urban greening, ecological restoration and agricultural modernization can all produce situations in which one environmental indicator improves while another deteriorates. The paper thus encourages a more mature framework: Environmental policy should be judged by multiple outcomes rather than by the moral label attached to the technology or program.
The paper’s own findings point toward spatial optimization
The study’s heterogeneous results are as important as its average effect. The estimated decline in bird diversity is substantially stronger in non-desert regions, particularly in wealthier areas with more complex habitats. This finding changes the policy problem. The relevant choice is not simply PV development versus biodiversity protection. It is where PV should be built so that the same unit of clean electricity is produced at a lower ecological cost.
That distinction supports a clear planning principle for China: large-scale ground-mounted PV should be concentrated, as far as practicable, in deserts, Gobi areas, degraded land, mining subsidence zones and other low-conflict locations where land competition and habitat disturbance are comparatively limited. These regions often combine abundant solar resources, large contiguous areas and low population density, making them particularly suitable for utility-scale projects.
Such a strategy is particularly feasible in China because the country has developed an extensive ultra-high-voltage (UHV) transmission network under its broader West-to-East Power Transmission strategy, enabling large volumes of electricity generated in the resource-rich western and northern regions to be delivered over long distances to the major demand centers in the east. This infrastructure helps overcome one of the principal geographical constraints on concentrating utility-scale solar generation in remote desert and Gobi regions. In densely populated regions or areas with high ecological and agricultural value, rooftop PV, industrial sites, transport corridors and other already-developed spaces should play a larger role.
This is not an argument that deserts are ecologically empty. Drylands contain distinctive plants, insects, reptiles, mammals and birds, and some recover very slowly once disturbed. The correct principle is therefore not “build in deserts regardless of ecological conditions,” but prioritize deserts, Gobi areas and degraded land while excluding biodiversity hotspots, migration corridors, fragile habitats and other sites of high ecological value. Renewable-energy maps should incorporate not only solar irradiation, construction costs and transmission capacity, but also habitat value, water stress, migration routes and ecosystem vulnerability.
The Hami 50MW Molten Salt Tower Solar Thermal Power Plant in the Gobi Desert of Xinjiang, northwest China, October 10, 2024. /CFP
The missing counterfactual: ecological cost is only one side of the ledger
From a public-policy perspective, the paper’s most important limitation is more fundamental: It identifies an ecological cost without evaluating the corresponding social benefits of PV expansion. That is entirely legitimate for a study focused on biodiversity, but it is not sufficient for deciding whether a society should build more or less solar power.
Solar generation can displace coal and other fossil-fuel generation, reduce greenhouse-gas emissions and conventional air pollution, diversify energy supplies, strengthen energy security and reduce dependence on imported fuels. Climate mitigation is itself relevant to biodiversity because climate change threatens habitats and species on a far broader geographical scale. A local ecological cost therefore cannot be interpreted in isolation from the environmental and social damage avoided elsewhere.
The correct counterfactual is not a solar farm on one side and an untouched natural world on the other. The realistic comparison is among alternative ways of satisfying energy demand, each of which carries a footprint. Coal requires mining, transport and combustion; oil and gas require extraction and pipeline networks; hydropower alters rivers and inundates land; nuclear power requires mining, plants, cooling systems and waste management; wind power requires foundations and grid connections. The fact that one technology has an ecological cost tells us very little until we know the costs of the alternatives.
If a solar project produces a measurable local decline in bird diversity but displaces an energy source that causes greater climatic pollution and ecological damage over its life cycle, rejecting the solar project may increase rather than reduce total environmental harm. Conversely, if the same electricity can be produced on rooftops or degraded land at modest additional cost, then destroying a biologically rich habitat would be difficult to justify. The policy problem is therefore comparative, not absolute.
A rational assessment should place biodiversity effects alongside carbon reduction, avoided air pollution, energy security, land opportunity costs, transmission requirements, local economic benefits, ecological irreversibility and the availability of alternative sites. This is a utilitarian approach in the serious sense of the term: not “economic growth at any cost,” but an attempt to count all significant benefits and harms, including ecological values that markets often fail to price. Biodiversity deserves substantial weight in such decisions, but weight is not the same as an automatic veto.
What the paper should inspire in Chinese PV policy
Seen in this light, the paper will encourage China to shift from simple capacity expansion to cautious, spatially optimized expansion. As the scale of PV deployment increases, the geography and quality of new capacity become as important as the quantity.
A rational hierarchy would place large centralized projects first in deserts, Gobi areas, degraded land, former mining areas and other sites with relatively low ecological and agricultural opportunity costs, while subjecting biodiversity hotspots, wetlands, migration corridors, ecologically rich grasslands and prime agricultural land to much stricter thresholds. In regions where land is scarce or ecological value is high, distributed PV on rooftops, factories, parking structures, transport infrastructure and other built environments should receive greater priority.
Environmental assessment should also move upstream. Biodiversity should be considered before a site is effectively chosen, not merely evaluated after project design is already advanced. The objective is to identify conflicts early, compare alternative locations, redesign projects where necessary and monitor ecological effects throughout construction and operation. Such an approach turns biodiversity evidence from a reason for paralysis into a tool for better planning.
The appropriate objective is therefore neither to maximize solar capacity regardless of ecology nor to maximize biodiversity preservation regardless of energy and human needs. It is to maximize the combined social value of clean energy, climate mitigation, energy security, economic development and ecological conservation. The paper’s heterogeneous findings are valuable precisely because they help make that optimization more concrete.
Conclusion: development, nature and rational choice
Human civilization has never advanced without altering nature; the task of rational policy is not to eliminate all ecological disturbance, which is impossible, but to distinguish necessary and beneficial transformation from avoidable and excessive destruction.
The history of development makes this plain. The Aswan High Dam brought electricity, irrigation and flood control while transforming the ecology of the Nile. Highways connect cities and expand commerce while fragmenting habitats and disturbing wildlife migration. Reservoirs secure water supplies and generate electricity while inundating terrestrial ecosystems and obstructing fish movement. Modern agriculture feeds billions while representing one of the largest transformations of natural habitats in human history. Renewable energy belongs to the same world of unavoidable trade-offs.
The existence of an ecological consequence is therefore not, by itself, an argument against an activity. The decisive questions are whether the benefit is sufficiently important, whether the ecological cost is proportionate, whether less damaging alternatives exist, and whether the remaining damage can be avoided, reduced, restored or compensated. That is the standard by which solar projects should be judged as well.
The enduring contribution of “China’s Solar Expansion Policy Reduces Bird Diversity” is therefore not that it gives society a reason to retreat from solar power. It gives policymakers a reason to abandon simplistic environmentalism. Solar power is not ecologically innocent, but neither is the energy system it replaces. The appropriate response to evidence of biodiversity loss is better siting, stronger ecological safeguards and more comprehensive cost-benefit analysis.
A traditional Chinese expression – “to give up eating for fear of choking” – captures the danger of allowing the existence of risk to become an argument against necessary action. Choking is a genuine risk of eating; the rational response is to reduce that risk, not to stop eating. Likewise, evidence that PV development can damage biodiversity in particular places should make the energy transition smarter, not stop it.
The mature environmental question is not whether humanity should alter nature – it inevitably will – but whether we can choose the place, scale and form of that alteration so that necessary development produces the greatest overall benefit with the least avoidable ecological harm.
(If you want to contribute and have specific expertise, please contact us at opinions@cgtn.com. Follow @thouse_opinions on X to discover the latest commentaries in the CGTN Opinion Section.)

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Solar development is accelerating in some parts of Canada, while others are taking a more cautious approach as provinces and territories chart their own energy policies.
Phil McKay, Senior Director of Member Programs at the Canadian Renewable Energy Association (CanREA), told pv magazine that while figures for new solar additions in 2026 are not yet available, he is hearing anecdotally from the association’s members that it has been “a good year”, with many talking about growing interest in storage-paired systems.
Canada’s solar market is highly fragmented across its ten provinces and three territories. This is largely down to the country’s electricity system, which the federal government’s website describes as multiple, relatively-segregated grids that are governed and planned independently and generally trade more with the US than one another. McKay described it as “13 different markets.”
These markets are prioritizing solar buildout to different degrees. In April, Québec launched a solar incentive program, with provincial utility Hydro-Québec offering a direct cash rebate of CAN 1,000 ($720)/kW covering up to 40% of eligible installation costs for residential and customer customers. 
According to details on its website, the support cuts the current payback period of 25-30 years down to 10-12 years. It forms part of wider plans to integrate 3 GW of solar in Québec by 2035. “Speaking with local companies there, they’ve been ran off their feet with inquiries [since the launch],” McKay said.
Another solar market leader is Ontario, which backed 12 solar projects with a combined capacity of 915 MW through its long-term energy procurement exercise in April. Such procurements are a key driver of Canada’s solar market, with previous CanREA analysis expecting them to be a large contributor to a forecasted 21 GW of solar by 2035.
The awarded projects in Ontario are granted 20-year agreements and are expected to begin commercial operation by the start of May 2030. McKay added that the approvals include agrivoltaics projects. “This is an open cost-competitive environment where agrivoltaics are competing with gas, which is so great to see,” he said.
Other regions of the country are starting to entertain a shift from net-metering to net-billing. British Columbia has replaced net metering with a fixed CAN 0.10/kWh export rate below retail, while New Brunswick is proposing a similar shift to below-retail compensation for surplus solar generation.
“Its all based on the same premise that solar isn’t as valuable as we’ve been making it out to be and solar customers are getting a free ride,” McKay explained. “There is huge pushback in the province, a lot of people are very upset about it.”
McKay spoke with pv magazine soon after the US placed 50% tariffs on many billions of dollars worth of Canadian goods going into the States last weekend. He said the uncertainty around US policy decisions impacts the entire sector.
“Everything [the US administration] does affects us, even content requirements on Chinese imports can create pathways for us. It’s hard to forecast where this goes because two weeks ago, we didn’t know we’d face these tariffs,” he said.
Canada’s Prime Minister Mark Carney responded to the latest tariffs with a speech that McKay said reiterated commitments from the spring budget to double the electricity grid with sustainable energy. 
“That’s very policy-driven language for solar, wind, and storage markets,” McKay said. He added that the ‘build Canada strong’ narrative is helping to unify the country around energy infrastructure.
“We’re finally talking about cross-Canada transmission lines and nation-building projects,” he said. “That’s exciting because it’ll open up the solar market and help balance the grid.”
On the other end of the scale, McKay shared that Canada’s grassroots solar movement is also picking up. Discussions around plug-in solar are developing, with the Canadian Standards Association currently debating UL 3700, a bi-national safety framework for Canada and the US that covers interactive plug-in solar systems.
McKay explained that while the standards ecosystem is engaged, progress is expected to move slowly. In the meantime, community and environmental organisations are starting to show interest in such products. “They see these systems as energy freedom,” McKay said. “A way to give Canadians a choice over whether we burn fossil fuels or not.”
McKay added that some large authorities, such as Ontario’s Electrical Safety Authority, are saying they will back UL 3700-compliant products, but he also confirmed that no such products are yet available.
“A few manufacturers are starting to design products to that standard,” McKay said. “It’s nascent, [now] waiting for the next steps before getting the standards, then we can unlock the whole country.”
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Free-On-Board (FOB) China TOPCon mainstream PV module prices rose this week, as firmer upstream prices increased production costs and prompted module manufacturers to raise their offer indications.
According to the OPIS Global Solar Markets Report released on Aug. 25, the Chinese Module Marker (CMM), the OPIS benchmark assessment for TOPCon modules below 645W from China, rose 2.86% week on week to $0.108/W FOB China.
The OPIS FOB China TOPCon module forward curve showed sharper price increases for earlier loading periods. Prices for Q1 2027 and Q2 2027 loading rose 1.90% and 0.95% week on week to $0.107/W and $0.106/W, respectively. Meanwhile, Q3 2027 loading prices were adjusted 0.95% lower to $0.105/W.
One module buyer attributed the recent price increases largely to the U.S. Section 232 tariffs, which have lifted prices across the supply chain. Set to take effect on Dec. 4, the measures will establish minimum import prices of $100/kg for ingots and wafers, $0.22/W for cells and $0.38/W for modules, alongside a 15% tariff on covered polysilicon derivatives.
However, the source said module pricing for overseas utility-scale projects remains largely flat, including for 2027 delivery, with the recent increases lacking long-term fundamental support and driven more by short-term market sentiment and tariff expectations.
A top-10 module manufacturer told OPIS that despite higher guidance and offer prices from major producers, transacted prices for mainstream modules have yet to follow. Some producers have raised offers for overseas projects, but negotiated deal levels continue to fall short of those indications.
The producer added that there is industry consensus that module prices cannot be sustained at recent highs, with asking prices elevated but actual deals concluding lower due to weak demand and buyers’ understanding of the underlying cost drivers.
Another tier-1 module producer said the recent firmness in upstream prices was linked to short-term U.S.-related demand. Higher input prices have pushed module production costs higher, prompting the manufacturer to pause cell purchases while monitoring market developments.
FOB China TOPCon M10 cell prices rose 16.16% week on week to $0.0532/W, while 210R cell prices increased 17.00% to $0.0523/W, according to the same report. Prices for both cell formats have risen about 34% since Aug. 4.
While persistently elevated cell prices could provide some near-term support for module prices, the producer said upstream prices appeared to be nearing their peaks, limiting the scope for further significant increases.
Another downstream producer echoed a similar view, noting that the upstream price movements of recent weeks have been significant but are likely to be short-lived. The company has temporarily suspended offers for medium-to-long-term orders due to the heightened cost uncertainty.
According to a market analyst, the outlook will also hinge on whether Chinese module manufacturers absorb the higher costs or pass them on to buyers. With module prices remaining broadly flat, manufacturers may be forced to continue selling below production costs, while passing higher costs through to end-users could undermine project economics for solar developers, adding further pressure to already weak demand.
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 views and opinions expressed in this article are the author’s own, and do not necessarily reflect those held by pv magazine.
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Ethan Ellis, Community Journalist
Published: August 28, 2026 at 5:50 PM
Ethan Ellis, Community Journalist
FRANKLIN CO., Va. – A Franklin County Circuit Court judge has approved the controversial Constitution Solar Project in Franklin County’s Henry community, allowing the more than 35-acre solar development to move forward despite opposition from a majority of the county’s Board of Supervisors.
The board voted against the project in December, with five supervisors opposing it and Union Hall District Supervisor Dan Quinn casting the lone vote in favor.
Blue Ridge District Supervisor Tim Tatum, who represents the area where the project would be located, said his primary concern is what will happen to the property when the solar project reaches the end of its useful life.
“What happens 20 years from now, or 25 years from now, or whenever that company goes under? Who’s going to clean the mess up?” Tatum said.
Tatum said the board’s decision was intended, in part, to send a message about those concerns.
“We voted it down more or less to make a statement,” Tatum said. “I know they put up a bond to cover cleanup, but is it set to progress with inflation? What they put aside now might not be enough to cover it 20 years from now.”
Quinn said the board’s decision came down to whether the project complied with Franklin County’s comprehensive plan.
“Our one narrow decision point was: Did this project conform with the comprehensive plan?” Quinn said.
Quinn said it did.
“And none of the other supervisors had any rationale for citing a reason that it did not conform with the comprehensive plan,” he said.
Because the project was going in an unzoned area of the county, the only other hurdle it faced was that comprehensive plan Quinn mentioned. The plan sets aside 1,500 acres of county land for solar use, meaning there was no legal reason county leaders could say no.
Copyright 2026 by WSLS 10 – All rights reserved.
Ethan Ellis officially joined the WSLS 10 News team in May 2025.
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World’s First Solar-Powered Ambulance Could Bring Healthcare to Remote Africa  GreekReporter.com
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Reel agrees multi-buyer PPA for Danish solar park  Renewables Now
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KITCHENER, ON, Aug. 27, 2026 /PRNewswire/ — Canadian Solar Inc. (“Canadian Solar” or the “Company”) (NASDAQ: CSIQ) today announced financial results for the second quarter ended June 30, 2026.
Second Quarter Highlights

During the quarter, shipments within our Manufacturing segment were in line with expectations, with slight operational outperformance in battery energy storage, as we continue to navigate global macroeconomic uncertainties with agility. We delivered 3.1 GW of solar modules, with nearly half shipped to our North American home base. In addition, we achieved 3.7 GWh of energy storage shipments to internal and external projects under execution, serving utility-scale projects across North America, EMEA, Asia Pacific and Latin America. As we double down on our U.S. manufacturing strategy, we continue to rebalance our global project development business and optimize capital allocation across our core growth engines.”
Xinbo Zhu, Senior VP and CFO, added, “For the quarter, we achieved total revenue of $1.2 billion with a gross margin of 13.9%. The sequential decrease in gross margin was primarily driven by the absence of a tariff refund recognized in the prior period, alongside normalized energy storage margins. Net loss attributable to shareholders was $77 million, or $1.40 per share, and we ended the period with a cash position of $1.9 billion.
Recurrent Energy's quarterly performance was light, primarily due to the deferral of planned project sales to the second half. Electricity revenue increased sequentially following the COD of a major utility-scale solar project in Spain. Within our global pipeline, we are focusing on quality, prioritizing value realization from mature, high-margin opportunities; pruning less attractive projects; and managing operating expenses to protect profitability.”
Second Quarter 2026 Results
Total solar module shipments recognized as revenue in Q2 2026 were 3.1 GW, up 25% quarter-over-quarter (“qoq”) and down 60% year-over-year (“yoy”).
Total battery energy storage shipments recognized as revenue in Q2 2026 were 3.7 GWh, up 82% qoq and up 73% yoy. Of the total, 471 MWh were shipped to internal projects under execution, with associated revenue to be recognized in subsequent quarters.
Net revenues were $1.2 billion in Q2 2026, up 12% sequentially and down 29% yoy. The sequential increase reflects higher sales of solar modules and battery energy storage solutions, partially offset by lower project sales. The yoy decrease reflects a decline in solar module and project sales.
Gross profit was $168 million, compared to $271 million in Q1 2026 and $505 million in Q2 2025. Gross margin was 13.9%, compared to 25.1% and 29.8% in Q1 2026 and Q2 2025, respectively. The sequential and yoy decrease in gross margin was primarily due to the absence of IEEPA tariff refund benefits recognized in the previous quarter and the absence of the release of unrealized profit upon sales-type leasing of a U.S. project in Q2 2025.
Operating expenses were $240 million, compared to $198 million in Q1 2026 and down from $378 million in Q2 2025. The sequential increase reflects higher ramp-up costs and logistics costs. The yoy decrease is mainly due to decrease in impairment charges related to certain solar and storage assets, as well as manufacturing assets. Operating expenses represented 19.8% of revenue, compared to 18.4% in Q1 2026 and 22.3% in Q2 2025.
Net loss attributable to Canadian Solar in accordance with generally accepted accounting principles in the United States of America (“GAAP”) in Q2 2026 was $77 million, or a net loss of $1.40 per share, compared to a net loss of $32 million, or a net loss of $0.71 per share, in Q1 2026, and a net income of $7 million, or a net loss of $0.08 per share, in Q2 2025. Net income or loss per diluted share includes the dilutive effect of convertible bonds, as applicable, and paid-in-kind dividends on the Recurrent Energy redeemable preferred shares.
Net cash flow used in operating activities in Q2 2026 was $181 million, driven by changes in working capital, compared to net cash flow used in operating activities of $209 million in Q1 2026 and net cash flow provided by operating activities of $189 million in Q2 2025.
Total debt, including financing liabilities, was $7.1 billion as of June 30, 2026, including $4.1 billion, $2.5 billion, and $0.4 billion related to Recurrent Energy, Manufacturing, and convertible notes, respectively. Total debt increased from $6.8 billion as of March 31, 2026, mainly due to new non-recourse debt drawdown for construction of solar and battery energy storage projects under Recurrent Energy in the U.S. Total non-recourse debt under Recurrent Energy as of June 30, 2026, was $2.6 billion.
Business Segments
Canadian Solar's business is organized into two segments:

Solar Modules and Solar System Kits
The Company shipped 3.1 GW of solar modules and solar system kits to more than 70 countries and regions in Q2 2026.
Consistent with the Company's transition from volume-driven growth to high-value creation, the Company will focus its capacity disclosure on strategic markets rather than aggregate global manufacturing capacity.
In the U.S., the Company operates a 5 GWp solar module factory in Mesquite, Texas, which is currently being expanded to a nameplate capacity of 10 GWp, with completion expected in the second half of 2026.
The Company is also continuing to advance its flagship, state-of-the-art heterojunction technology (“HJT”) solar cell factory in Jeffersonville, Indiana. In response to strong customer demand, the Company is in the process of increasing its production capacity beyond 6 GWp, with additional production lines being installed and commissioned through 2026.

As of June 30, 2026, e-STORAGE contracted backlog, including contracted long-term service agreements, stood at $3.5 billion. These signed orders represent binding customer commitments and provide significant earnings visibility over a multi-year period.
Recurrent Energy
As of June 30, 2026, the Company had a total global solar project development pipeline of approximately 22 GWp and a battery energy storage project development pipeline of 84 GWh.
The business model consists of three key drivers:

As of June 30, 2026, the Company's total solar project development pipeline was 21.7 GWp, including 1.7 GWp under construction, 2.2 GWp of backlog, and 17.7 GWp of projects in advanced and early-stage development. The pipeline includes projects that may be retained for long-term ownership and operation or sold to third parties, depending on market conditions and capital allocation priorities. The pipeline stages are defined as follows:

The following table presents the Company's total solar project development pipeline.

Construction

Development

Development

(“EMEA”)

to third parties.

Project Development Pipeline – Battery Energy Storage
As of June 30, 2026, the Company's total battery energy storage project development pipeline was 84.1 GWh, including 600 MWh under construction, 4.4 GWh in backlog, and 79.1 GWh of projects in advanced and early-stage development. The pipeline includes projects that may be retained for long-term ownership and operation or sold to third parties.
The table below sets forth the Company's total battery energy storage project development pipeline.

Construction

Development

Development

sold to third parties.

Business Outlook
The Company's business outlook is based on management's current views and estimates, taking into account factors such as existing market conditions, order book, production capacity, input material prices, foreign exchange fluctuations, the anticipated timing of project sales, and the global economic environment. This outlook is subject to uncertainty with respect to, among other things, customer demand, project construction and sale schedules, product sales prices and costs, supply chain constraints, and geopolitical conflicts. Management's views and estimates are subject to change without notice.
In Q3 2026, the Company expects total revenue to be in the range of $1.3 billion to $1.5 billion. Gross margin is expected to be between 13.5% and 15.5%. Total module shipments recognized as revenue are expected to be in the range of 3.5 GW to 3.8 GW. Total battery energy storage shipments in Q3 2026 are expected to be in the range of 3.4 GWh to 3.8 GWh.
The Company is reiterating its guidance of 6.5 GW to 7.0 GW of solar modules and 4.5 GWh to 5.5 GWh of battery energy storage solutions for the U.S. market in 2026.
Colin Parkin, CEO of Canadian Solar, commented, “We expect margins in the third quarter to remain stable, as we continue to scale our integrated U.S. solar manufacturing strategy, though ramp-up costs associated with our solar cell facility in Jeffersonville, Indiana, will weigh on profitability for the remainder of the year. We anticipate the cadence of U.S. solar and storage shipments to accelerate in the second half, with each quarter of 2026 delivering larger volumes than the last. Meanwhile, at Recurrent, we expect to close the delayed project sales from the second quarter, driving a sequentially stronger third quarter.”
Recent Developments
Canadian Solar
On August 18, 2026, Canadian Solar announced the successful resolution of the remaining U.S. patent litigation brought by Maxeon Solar Pte. Ltd. (“Maxeon”). Maxeon's patent infringement lawsuit in the Federal District Court was dismissed with prejudice, and the U.S. Court of Appeals for the Federal Circuit vacated the relevant portion of the Patent Trial and Appeal Board decision in Canadian Solar's favor.
On July 30, 2026, Canadian Solar announced that its U.S.-manufactured TOPCon and HJT Low Carbon HP modules achieved FM Approvals recognition under the FM 4478 and FM 4480 identified component standards, making them the first FM Approvals PV modules listed as identified components for severe hail zones.
On July 14, 2026, Canadian Solar announced that it was named a Tier 1 supplier for both battery energy storage systems and PV modules on S&P Global Energy's Tier 1 Cleantech Companies list. S&P Global Energy's selection criteria span market presence and cumulative equipment shipments; annual market share; scale; global manufacturing diversification; financial performance via key financial indicators, sustainability factors, and more.
On June 24, 2026, Canadian Solar announced that its Baotou ingot facility and Suqian solar cell manufacturing facilities earned Silver Level Solar Stewardship Initiative (SSI) Supply Chain Traceability Certification, becoming the first manufacturer to receive Silver status for both ingot and cell production.
On June 22, 2026, Canadian Solar announced the launch of its new TOPCon 3.0 high-power-density module delivering up to 670 Wp power output and 24.8% conversion efficiency of 24.8% for utility-scale and C&I applications, with mass global shipments scheduled to begin in August 2026.
On June 1, 2026, Canadian Solar announced the publication of its 2025 Corporate Sustainability Report. The sustainability disclosures are aligned with global standards established by the Sustainability Accounting Standards Board (SASB) and Global Reporting Initiative (GRI), with reference to the International Financial Reporting Standards (IFRS) set by the International Sustainability Standards Board (ISSB).
Manufacturing: CS PowerTech and CSI Solar
On August 13, 2026, Canadian Solar announced its energy storage solutions business, e-STORAGE, successfully completed Large-Scale Fire Testing (LSFT) for its KuBank 3.0 C&I energy storage system under the latest UL 9540A:2026 standard. The test was independently verified by TÜV Rheinland and Energy Safety Response Group (ESRG), and the system has entered mass production for worldwide availability.
On July 24, 2026, Canadian Solar announced that its subsidiary CS PowerTech Inc., the largest silicon PV manufacturer in the U.S., officially launched the first phase of its flagship PV cell manufacturing plant in Jeffersonville, Indiana. The facility is the first plant in the U.S. designed to produce advanced HJT bifacial N-type solar cells. Combined with the Texas module facility, it creates a fully localized supply chain with an expected total annual cell capacity of over 6 GWp.
On June 25, 2026, Canadian Solar announced e-STORAGE signed a supply contract with an electric utility in Florida to supply a 95 MW / 426 MWh DC battery energy storage system (BESS). Featuring its proprietary SolBank 3.0 battery blocks which are fully produced at Canadian Solar's manufacturing facilities, the installation is planned for the second half of 2027, with commercial operations targeted for early 2028.
On June 24, 2026, Canadian Solar announced e-STORAGE will supply a 75 MW / 381 MWh DC BESS to Apex Clean Energy in Branch County, Michigan, co-located with Apex's operating Coldwater Solar facility. Under the agreement, e-STORAGE will deliver an integrated solution combining SolBank 3.0 battery blocks, Power Conversion Systems, and its proprietary EQ‑S Energy Management System, with deliveries scheduled to begin in early 2027 and commercial operation targeted for mid-2027.
On June 23, 2026, Canadian Solar announced e-STORAGE will deliver an 8 MW / 40 MWh BESS, co-located at an existing combined-cycle gas power plant in Rizziconi, Calabria, to Axpo. This partnership marks e-STORAGE's first battery storage project in Italy.
Recurrent Energy
On August 13, 2026, Canadian Solar announced that its subsidiary, Recurrent Energy, successfully closed $695 million in project financing and tax equity for its 330 MW Cobalt Solar facility located in Riverside County, California. The debt financing package, totaling approximately $484 million, was led by Mitsubishi UFJ Financial Group, Inc. (MUFG) and Nord/LB, while a parallel $211 million tax equity investment was secured from Wells Fargo. Currently under construction with Blattner Energy serving as the EPC provider, the project is expected to reach commercial operation by the end of 2027.
On August 12, 2026, Canadian Solar announced Recurrent Energy reached commercial operation ahead of schedule for its 150 MWac Carwarp Energy Park near Mildura, Victoria, Australia. Backed by a long-term PPA with Microsoft, the asset incorporates approximately 243,000 high-efficiency Canadian Solar TOPCon modules and holds planning and grid approvals to incorporate a hybrid 120 MW BESS.
On July 6, 2026, Canadian Solar announced an executive leadership transition at Recurrent Energy. Mr. Dylan Marx was appointed Chief Executive Officer, succeeding Mr. Ismael Guerrero, who will remain as a non-executive advisor through December 31, 2026.
Conference Call Information
The Company will hold a conference call on Thursday, August 27, 2026, at 8:00 a.m. U.S. Eastern Time to discuss the Company's second quarter 2026 results and business outlook. The dial-in phone number for the live audio call is +1-877-704-4453 (toll-free from the U.S.) or +1-201-389-0920 from international locations. The conference ID is 13762069. A live webcast of the conference call will also be available via the webcast link on the investor relations section of Canadian Solar's website.
A replay of the call will be available after the conclusion of the call until 11:00 p.m. U.S. Eastern Time on Thursday, September 10, 2026, and can be accessed by dialing +1-844-512-2921 (toll-free from the U.S.) or +1-412-317-6671 from international locations. The replay pin number is 13762069. A webcast replay will also be available via the webcast link on the investor relations section of Canadian Solar's website.
About Canadian Solar Inc.
Canadian Solar is one of the world's largest solar technology and renewable energy companies. Founded in 2001 and headquartered in Kitchener, Ontario, the Company is a leading manufacturer of solar photovoltaic modules; provider of solar energy and battery energy storage solutions; and developer, owner, and operator of utility-scale solar power and battery energy storage projects. Over the past 25 years, Canadian Solar has successfully delivered nearly 180 GW of premium-quality solar photovoltaic modules to customers across the world. Through its energy storage solutions business e-STORAGE, Canadian Solar has shipped over 23 GWh of battery energy storage solutions to global markets and had a contracted backlog of $3.5 billion as of June 30, 2026. Since entering the project development business in 2010, Canadian Solar has developed, built, and connected approximately 12.4 GWp of solar power projects and 6.4 GWh of battery energy storage projects globally. Its geographically diversified project development pipeline includes approximately 22 GWp of solar and 84 GWh of battery energy storage capacity in various stages of development. Canadian Solar is one of the most bankable companies in the solar and renewable energy industry, having been publicly listed on the NASDAQ since 2006. For additional information about the Company, follow Canadian Solar on LinkedIn or visit www.canadiansolar.com.
Safe Harbor/Forward-Looking Statements
Certain statements in this press release, including those regarding the Company's expected future shipment volumes, revenues, gross margins, and project sales are forward-looking statements that involve a number of risks and uncertainties that could cause actual results to differ materially. These statements are made under the “Safe Harbor” provisions of the U.S. Private Securities Litigation Reform Act of 1995. In some cases, you can identify forward-looking statements by such terms as “may”, “will”, “expect”, “anticipate”, “future”, “ongoing”, “continue”, “intend”, “plan”, “potential”, “prospect”, “guidance”, “believe”, “estimate”, “is/are likely to” or similar expressions, the negative of these terms, or other comparable terminology. These forward-looking statements include, among other things, our expectations regarding global electricity demand and the markets for solar power and battery energy storage; our growth strategies, future business performance, and financial condition; our ability to sustain our project development and balance long-term asset ownership with selective project sales; our ability to monetize project portfolios, manage supply chain fluctuations, and respond to economic factors such as inflation and interest rates; our outlook on government incentives, and policy support schemes, trade measures, regulatory developments, and geopolitical risks; our expectations for project timelines, costs, offtake and returns; competitive dynamics in solar and storage markets; our ability to execute supply chain, manufacturing, and operational initiatives; access to capital, debt obligations, and covenant compliance; relationships with key suppliers and customers; technological advancement and product quality; and risks related to intellectual property, litigation, and compliance with environmental and sustainability regulations. Other risks are described in the Company's filings with the Securities and Exchange Commission, including its latest annual report on Form 20-F filed on April 10, 2026. Although the Company believes that the expectations reflected in the forward-looking statements are reasonable, it cannot guarantee future results, level of activity, performance, or achievements. Investors should not place undue reliance on these forward-looking statements. All information provided in this press release is as of today's date, unless otherwise stated, and Canadian Solar undertakes no duty to update such information, except as required under applicable law.
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The following tables provide unaudited select financial data for the Company's Manufacturing and Recurrent Energy businesses.
 

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Bringing solar modules into the United States will cease to be financially sensible under the newly imposed Section 232 tariffs on polysilicon-based goods, as stated by Intertek CEA. This evaluation was presented during a webinar held on August 27, 2026, by the quality assurance and supply chain services firm.
Christian Roselund, who oversees policy research at Intertek CEA, indicated that he anticipates U.S. module producers will take the lead in the market come 2027, driven by the elevated costs of imported solar PV modules resulting from Section 232. The tariff framework sets minimum import prices (MIP) for polysilicon, silicon ingots and wafers, solar cells, and modules, along with an additional 15% tariff. The MIP stands at US$0.38 per watt for modules and US$0.22 per watt for cells.
Even with the projected dominance of U.S. module manufacturers starting in 2027, Roselund noted that their profit margins are likely to be squeezed by the higher expenses associated with importing cells. At present, the U.S. faces a gap of roughly 50GW between its solar cell and module production capacities, with about 11GW of cells available to support over 60GW of PV module capacity. Consequently, most module-only manufacturers will keep depending on imports, which will erode their margins and push module prices upward.
A comparable scenario is expected for cell-only producers such as ES Foundry or Suniva, as they will need to cover the cost of imported silicon wafers at the MIP of US$100 per kilogram. These cell makers will then increase their prices when selling to module factories, thereby transferring expenses along the supply chain.
The notable exception lies with vertically integrated firms, which are positioned to gain the most from the Section 232 duties. Such companies are scarce in the current U.S. solar market. Hanwha Qcells manufactures both solar PV cells and modules, as do T1 Energy, Toyo Solar, and several others, yet the data reveal that cell and especially wafer production trails module assembly considerably.
These companies, whether they have U.S.-based cell production or captive cell facilities overseas, benefit from the lower MIPs at earlier stages of the supply chain. There are greater advantages to importing wafers at roughly US$0.12 per watt or cells at US$0.22 per watt, while completing the remaining manufacturing steps within the U.S.
Intertek CEA currently reports that imported modules in the U.S. are priced around US$0.46 per watt, while U.S. modules using foreign cells range from US$0.38 to US$0.44 per watt. Modules with U.S.-made cells are priced at US$0.45 to US$0.50 per watt, reflecting the scarcity of domestic cells, and fully domestic supply chains, which are confined to output from Corning and Hemlock, sit near US$0.50 per watt due to their protection from future tariffs.
Joseph C. Johnson, associate director for market intelligence at Intertek CEA, characterized these prices as a modest market overreaction to the introduction of new costs. They may therefore adjust downward over time, but the overarching direction is evident: U.S. module prices are climbing, which favors a limited set of well-established players.
The webinar also touched on the potential for more competitive tactics among manufacturers as the industry adjusts to the new circumstances, with some entities discovering methods to offer modules at lower prices. This trend is particularly relevant heading into the 2030s, when CEA projects that U.S. module manufacturing capacity will far outstrip annual demand. Solar installations are anticipated to stay relatively steady through 2030, whereas module capacity could surpass 115GW, and even cell capacity might exceed deployment levels based on existing credible expansion plans.
Ultimately, the considerable uncertainty surrounding the Section 232 policy and other elements of the U.S. solar market discourages investment in new upstream manufacturing, according to Roselund. He emphasized that this policy is not fixed, as the Secretary of Commerce retains the authority to modify the MIPs over time in response to market conditions, potentially leading to unpredictable fluctuations.
Additionally, the U.S. is confronting new restrictions on power equipment such as inverters and transformers, along with various other tariffs that compound the Section 232 duties, and the expiration of tax credits designed to promote solar adoption. Establishing new cell or wafer facilities can entail investments of up to US$165 million per GW and several years of construction before becoming operational. Roselund observed that by the time such facilities come online, the 45X Advanced Manufacturing tax credit would be nearing its expiration, thereby eliminating a key incentive for domestic content and cell production in the U.S.
The Section 232 update is poised to substantially affect the U.S. solar supply chain, a topic slated for deeper examination at the PV CellTech USA conference scheduled for October 13-14, 2026. The event will cover the policy and investment environment for U.S. solar manufacturing across the supply chain, featuring speakers like Mike Carr, executive director of the Solar Energy Manufacturers for America (SEMA) Coalition.
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China Built a Solar Panel Empire—and May Have Seriously Messed Up Its Birds  AOL.com
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“If the law gives us a path to say ‘no’, I think we all should know about it.”
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In Virginia, two Hampton Roads cities, Chesapeake and Virginia Beach, are putting the brakes on the fast-growing data center industry amid concerns over land use, noise, water demand, and rising energy costs.
Chesapeake voted to stop allowing data centers by-right use in certain areas, while Virginia Beach approved a 12-month pause on permits for new facilities as it works on rules for the industry.
Local governments in southeast Virginia are taking a new approach to large digital infrastructure projects as they decide how much room they want to make for them, according to Virginia Business.
In Virginia Beach, the moratorium temporarily halts permits for data centers as a primary use until either a final ordinance is adopted or the 12-month window expires. In Chesapeake, developers can no longer move ahead automatically in certain zones and must instead win City Council approval one project at a time.
A basic problem has complicated Virginia Beach’s effort to write regulations: City officials have said there’s no standard industry definition for what qualifies as a data center. 
Zoning administrator Hannah Sabo told the Planning Commission, “One of the kinds of roadblocks or issues we’re running into is there’s no industry standard definition for a data center.”
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Vice Mayor Rosemary Wilson said the city wants oversight before those facilities can move into industrially zoned areas.
“In places that are zoned industrial, they could go in there by-right, and you know we don’t want that to happen to be able to just go in by-right without us having any say-so on it,” Wilson said, per Virginia Business.
As land for new projects becomes harder to find elsewhere in Virginia, data center development has spread beyond Loudoun County’s “data center alley,” the world’s largest concentration of data centers.
Those facilities can place major demands on electric infrastructure, and in Virginia, the effects are especially visible on the PJM grid, where capacity costs tied to growing power demand are already showing up on household utility bills.
In Chesapeake, opposition has centered on concerns over noise, shrinking rural land, electricity use, and environmental impacts, as Virginia Business reported. 
“Look, it’s not red or blue,” resident David Williams said at a council meeting. “It’s just people.”
Officials said potential data center sites also sat close to residential areas. As Virginia Business reported, more than 27,000 residentially zoned parcels were within 500 feet of land where a data center could have been developed.
Chesapeake’s action did more than end by-right development. As Virginia Business reported, it also confined data centers to industrial districts and has prevented them from connecting to groundwater. The city also asked Virginia Attorney General Jay Jones to weigh in on whether state law leaves any route to ban data centers entirely.
Across Virginia, other localities are also weighing stricter data center rules. After successfully pushing to remove the Fentress Airfield Overlay district from the ordinance, councilwoman Amanda Newins said the city needs more time to understand the industry’s full impact.
“I personally believe that we have to put your quality of life above the interests of an industry that is going to place an enormous demand on our water, electricity, our land, our infrastructure, while fundamentally changing the character of the communities around it,” she said.
During the moratorium, Virginia Beach plans to keep gathering input from industry representatives and other stakeholders while it studies setbacks, buffers, noise, and other standards.
Newins said residents deserve a definitive legal answer before city leaders say a ban cannot be done: “If the law gives us a path to say ‘no’, I think we all should know about it.”
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A researcher at Turkey’s Selçuk University has conducted a comparative analysis of multiple machine learning algorithms for predicting plane-of-array (PoA) irradiance on bifacial PV panels. The researcher used identical input conditions to predict PoA irradiance on both the front and rear sides of the panels.
“This study presented a comprehensive machine learning–based framework for predicting front-side and rear-side PoA irradiance in a bifacial photovoltaic system using routinely measured meteorological, surface-related, and temporal input variables,” researcher Ayşegül Toprak said in the paper. “This study demonstrates that accurate and interpretable prediction of both front and rear PoA irradiance can be achieved using a compact set of easily measurable inputs.”
The study used synchronized field measurements collected between Nov. 17, 2023, and May 29, 2024, from a vertical bifacial PV testbed operated by the US Department of Energy’s National Renewable Energy Laboratory (NREL) in Golden, Colorado. The testbed consisted of a vertically mounted bifacial PV array positioned close to the ground, along with meteorological sensors, ground-reflected irradiance measurements and six IMT reference cells.
The input dataset included global horizontal irradiance (GHI), diffuse horizontal irradiance (DHI), ambient temperature, wind speed, testbed albedo and a binary reflector variable, as well as hour_sin and hour_cos, which represent the daily solar cycle. Before model training, the researcher removed physically implausible zero values, sensor faults and records containing missing or inconsistent measurements.
Toprak then evaluated six regression algorithms: linear regression, k-nearest neighbors (KNN), support vector regression (SVR) with a radial basis function kernel, random forest (RF), extreme gradient boosting (XGBoost) and a feedforward multilayer perceptron (MLP). Each model was run separately for front and rear PoA irradiance using the same input variables and identical five-fold cross-validation partitions in MATLAB. Predictive accuracy was assessed using root mean square error (RMSE), mean absolute error (MAE) and the Pearson correlation coefficient (r).
The results showed that nonlinear models clearly outperformed linear regression in predicting both front- and rear-side irradiance. Random forest achieved the best performance for front PoA irradiance, with an RMSE of 0.188, an MAE of 0.061 and a correlation coefficient of 0.982. It was followed closely by MLP, XGBoost and SVR, all of which recorded correlation coefficients above 0.97.
Rear PoA irradiance proved more difficult to predict. Random forest again performed best, with an RMSE of 0.236, an MAE of 0.080 and an r value of 0.973, while MLP recorded the same RMSE but a slightly higher MAE of 0.086. Linear regression ranked last for both targets, with RMSE values of 0.682 for front PoA irradiance and 0.593 for rear PoA irradiance.
“The results indicate that front-side irradiance is primarily governed by global irradiance and diurnal solar geometry, whereas rear-side irradiance is strongly influenced by surface-related factors such as ground albedo and the presence of reflective ground cover, confirming the conditional and interaction-driven nature of rear-side irradiance formation in bifacial systems,” Toprak concluded.
The study, “Front and rear plane-of-array irradiance in bifacial photovoltaic systems: A machine learning-based prediction approach,” was published in Energy Reports.
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ROCK SPRINGS — The Rock Springs Police Department shared a Facebook post stating that the city does not use Flock cameras in response to recent vandalism of solar panels powering streetlights.
While the RSPD did not outright say the trend of destroying Flock cameras and the recent damage to solar panels were connected, the timing was close enough that the department felt the need to address it. Phylicia Lukacik, RSPD public information officer, referenced social media posts claiming that Flock cameras are being installed in and around Rock Springs. Lukacik told SweetwaterNOW that the city does not have any Flock cameras or automatic license plate readers. 
“We’ve seen how quickly something posted online can turn into something people accept as fact. One person makes an assumption, someone else shares it, and before long the information has traveled far beyond the original post,” the RSPD’s statement read. “By the time we’re dealing with damaged equipment, the rumor may have taken on a life of its own.”
The RSPD said not every camera, solar panel, or piece of equipment around town is a Flock camera, and much of it is simply part of the city’s infrastructure. The police department encourages residents to ask them questions about the equipment seen around Rock Springs, saying it would much rather clear something up than “have someone make an assumption based on a social media post and act on it.”
The RSPD asks residents not to remove, damage or tamper with city equipment. The solar panels and other components are there for a reason, and repairing them costs money and can affect services that the community relies on, the RSPD said. 
“We understand that cameras, privacy and surveillance are topics people have questions about. Those are legitimate conversations to have. But they need to start with accurate information,” the RSPD said. “Again, the City of Rock Springs does NOT use Flock cameras.”
The RSPD urges residents who witness someone tampering with or damaging city equipment to report it to law enforcement rather than handling it themselves. 
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Complex site topography can have a crucial bearing on a PV system’s energy yield. In a market characterised by tight margins and careful risk management, precision in terrain-aware modelling is an essential ingredient of smart engineering, writes Solargis CEO Marcel Suri.
In photovoltaics, terrain is not a cosmetic detail; it’s an important input into energy yield. The reality is that many utility-scale PV projects are not built on perfectly flat plots of land. On the contrary: they often sit on sloped, hilly or otherwise irregular grounds, with lots of variables that need to be taken into account.
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Complex topography affects the fundamentals behind PV performance in two ways. Optically, it changes shading behaviour and view factors. Electrically, it affects operating points and losses that depend on irradiance variability, temperature and angle of incidence. If the geometry used in the simulation does not match the geometry used in the design, the uncertainty introduced is not random, it is systematic. Wrong geometry in, wrong yield out.
This is why PV layouts should reflect real terrain: not only to reduce construction risk, but also to avoid inaccuracies in yield estimates. In practice, however, the connection between design and simulation is often weaker than it appears.
When you import a detailed terrain model and design a PV layout in 3D, you expect that when you hit “simulate”, the design will reflect the terrain. But many solutions on the market simplify the terrain, smoothing out slopes and removing local variations until the whole power plant is treated as if it were built on flat ground. The terrain is simply lost in the process.
So how can PV designers and developers avoid this and simulate energy yield using terrain that actually reflects reality?
The first challenge is obtaining and importing terrain data into the PV design tool. The first prerequisite, of course, is using software that supports terrain adapted design.
The industry still uses a wide range of terrain sources. Many tools rely on global DEM (Digital Elevation Model) layers with 30-90-metre resolution, but this data is often several years to decades old – adequate for early screening, but it can be misleading in mountainous terrain, in valleys, on terraced land, or on sites shaped by earthworks, roads and drainage.
For detailed design, you typically need to import your own terrain. The most robust format in practice is often GeoTIFF, because it carries georeferencing information in the file header. When you load multiple tiles, they can align correctly without manual stitching.
This leads to a key point that is easy to overlook. “Terrain” is not always terrain. Remote sensing products such as LiDAR (Light Detection and Ranging) may include tree canopies, buildings or temporary structures. Sometimes that is exactly what you want, because it can capture near shading without manually modelling every obstacle.
Sometimes it is a problem, because artefacts can behave like solid barriers in a 3D mesh. Power lines, for example, can be reconstructed as a wall rather than cables in the air, which then produces unrealistic shading and false collisions. Terrain data needs scrutiny before it becomes design truth.
Even when you have good terrain, you face a different constraint: computation. A detailed LiDAR or drone scan produces a so-called ‘point cloud’ that can be many gigabytes large. It is often unrealistic to manipulate these raw datasets interactively in a browser-based environment, and you do not want to waste rendering capacity on parts of the scene that have no relevance to PV geometry.
A useful approach is to convert elevation data into an optimised triangular mesh that preserves the important ridgelines and breaks in slope, while reducing triangles in areas where the surface is nearly flat.
For example, algorithms such as Mapbox’s “Delatin” illustrate this principle well: you accept controlled, quantified loss in geometric fidelity in exchange for a mesh that can be rendered and edited smoothly. The goal is maximum relevance where design decisions are sensitive to slope, curvature and local shading.
Once the terrain is usable, the central question becomes: does the PV layout actually conform to it, and does the simulator honour that same conforming geometry?
On undulating ground, table placement changes continuously. Row-to-row clearance, pile heights and tracker rotations interact with slope and local curvature. In tracker systems, the situation is especially unforgiving because a table that clears the terrain at one rotation angle may intersect it at another. If you only check geometry at a neutral position, you can miss collisions that occur during morning or afternoon tracking, or during stow events.
A terrain-adapted layout therefore needs two qualities. It must place structures on the terrain with realistic constraints, and it must preserve the detailed geometry into the simulation step, where shading and irradiance distribution are computed. If the simulator replaces that with a flattened approximation, you lose the entire point of terrain aware design.
On complex terrain, collisions are not rare edge cases. They are a predictable consequence of steep slopes, short clearances, and non-uniform table heights. Collisions can occur between adjacent tables in a deep valley, between tables and the terrain when legs are too short and between tables and equipment such as inverters placed beneath structures.
Smart collision detection is about preventing late-stage redesign and reducing the risk that constructability problems will arise after procurement decisions are made. Robust software solutions detect collisions immediately as the designer edits the layout, because waiting until a final design review is often too late and too expensive.
Most engineers are familiar with slope limits. At some point, a surface is simply too steep for economically reasonable construction and maintenance. But slope magnitude alone does not describe terrain suitability.
In the northern hemisphere, a given slope angle can have very different implications depending on whether it faces south or north. The same grade can ither support favourable module orientation or create persistent shading and access problems.
That is why terrain azimuth, the directional orientation of slopes, deserves to be treated as a first-order design variable rather than an afterthought. In practice, the best terrain-aware decisions come from combining slope magnitude, slope direction and local shading context into a single constraint view, rather than relying on a single “maximum slope” number.
Terrain also changes the effective tilt and exposure of PV surfaces, which can influence soiling dynamics and snow behaviour. In mountainous regions, especially, differences in surface tilt and local wind patterns can affect how quickly modules shed snow, how rainfall cleans surfaces and how long soiling persists.
This does not mean a model can “solve” snow and soiling perfectly. It means that if you ignore terrain in the geometry, you can end up applying loss assumptions that are inconsistent with how the plant will actually behave. For banks and investors, these inconsistencies show up later as performance surprises. For engineers, they show up as overdesign margins and uncomfortable uncertainty.
If you work on projects in complex topography, there is a straightforward question worth asking any simulation provider: how does your engine represent undulating terrain in the actual yield calculation?
Does it use the same 3D geometry you designed, or does it use a flattened layout?
Terrain-adapted PV design is not about making a 3D image of a solar power plant that looks impressive. It is about ensuring that the geometry you model is the geometry you simulate, and that the physics of the site is preserved all the way into bankable energy yield assumptions.
When simulation is done at the cell level on a realistic terrain model, the loss breakdown becomes more honest: you can see which energy losses are driven by topography, weather conditions, and which by design choices such as row spacing, tilt, or tracker geometry.
In a market where margins are tighter and risks are scrutinised harder than ever, precision in terrain-aware modelling is no longer a nice to have. It’s part of a smart engineering practice.
Marcel Suri is an entrepreneur and cofounder of the solar data and software company Solargis. He is an expert in solar resource, photovoltaics and geoscience. Holding a PhD in geography and geoinformatics, Marcel has made significant contributions to solar energy through science and peer-reviewed research. Driven by a passion for innovation, he is dedicated to improving the efficiency of digital tools and data resources and analytics that mitigate weather-related risks and elevate industry standards.

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Many energy-saving programs go underused because people do not know where to begin.
Photo Credit: York County Community Foundation
A new $400,000 grant in York County, Pennsylvania, could do far more than fund a new community position. It could also give residents a clearer path to the energy-saving programs, partnerships, and long-term planning that often help climate and cost-cutting efforts succeed.
The funding will support a full-time sustainability coordinator tasked with connecting organizations and helping shape a countywide resilience plan — a role that could be especially valuable for households trying to navigate rebates, efficiency upgrades, and local resources.
RegenAll is set to add two York County roles with support from the York County Community Foundation: a full-time sustainability coordinator and a part-time program manager.
As abc27 reported, the work is meant to “advance a community-driven vision to strengthen sustainability, resilience and cross-sector collaboration.”
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Foundation officials said the award emerged from a multi-year community engagement effort linked to the sustainable energy fund the organization created in 1993. According to the foundation, that fund has helped more than 130 nonprofits avoid over $15 million in “direct and avoidable energy costs.”
Many energy-saving programs go underused because people do not know where to begin. A county-level point person can help connect families with workshops, partnerships, and practical guidance that lowers utility bills while strengthening the local economy.
Going solar is also one of the best ways to save money on home energy over time. If you’re considering it, you can use EnergySage to get free solar installation estimates and compare quotes.
The York County expansion builds on work RegenAll began after launching in Lancaster County in 2021. The nonprofit describes its mission as “identifying and implementing local climate solutions through collaboration, education and community engagement.”
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After gaining traction in Lancaster County, including work at the Sunnyside Peninsula, it received a 2025 grant to grow its York County presence through workshops and events, according to the York County Community Foundation.
One of the coordinator’s central responsibilities will be creating a countywide Community Resilience Plan, the foundation said, with five focus areas: “Energy independence, food security, carbon neutrality, ecological regeneration, and thriving communities.”
The foundation said the project is expected to reach roughly 1,500 residents during the grant’s three-year span. It also said the coordinator will lead public-facing events and engagement opportunities, such as carbon neutral coffee meetups, green drinks, workshops, and partnership activities.
Better local coordination can help residents find programs for efficiency improvements, learn about cleaner technologies, and take advantage of incentives that might otherwise be easy to miss.
💡Go deep on the latest news and trends shaping the residential solar landscape
For homeowners, free tools can also make those choices easier. EnergySage‘s no-cost marketplace is designed to let shoppers compare options more confidently before making a major home-energy investment.
Readers can also check EnergySage’s solar map, which shows the average cost of a home solar panel system on a state-by-state level, along with details on local solar panel incentives. Together, those resources can help people get the best price for rooftop solar panels.
Adding battery storage to a solar setup is also one of the best ways to protect your home during outages, save money on energy, and go off-grid. You can explore EnergySage for information about home battery storage options, including competitive installation estimates.
As RegenAll executive director Alessandra DeJesus Restrepo said, per abc27, “Creating this full-time Sustainability Coordinator position enables RegenAll to turn community-driven goals into lasting, impactful action across the county.”
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“We didn’t go up, and that was good.”
Photo Credit: Amherst-Pelham Regional School District
Amherst, Massachusetts, cut its greenhouse gas pollution by nearly 13% below 2016 levels in fiscal year 2025, marking progress even as the town fell short of its first major climate benchmark.
As the Daily Hampshire Gazette reported, that first goal called for a 25% cut by 2025, meaning the town has achieved roughly half of the reduction it had planned for 2025.
A new greenhouse gas inventory shows Amherst’s total community emissions are 12.9% lower than they were in 2016. Emissions from municipal operations declined more sharply, coming in 17% below that baseline.
The town’s reduction timetable comes from its Climate Action, Adaptation and Resilience Plan, which the Town Council approved in November 2019. That plan set goals of 25% below 2016 emissions by 2025, 50% below by 2030, and carbon neutrality by 2050.
Officials still described the new numbers as evidence that Amherst is moving in the right direction. 
“We didn’t go up, and that was good,” Amherst sustainability director Stephanie Ciccarello said.
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She also noted the town is doing better than many comparable Massachusetts communities.
That view was also shared by James Ordway, the University of New Hampshire master’s student who prepared the report.
“Thirteen percent is lower than what we hoped for, but at least it’s going down, and not everyone’s going down,” he said.
Town government represents less than 2% of Amherst’s total emissions, but municipal emissions still dropped from 4,947 U.S. tons (4,488 metric tons) of carbon dioxide equivalent in fiscal year 2016 to 4,114 U.S. tons (3,732 metric tons) by fiscal year 2025.
Because the municipal share is so small, most community emissions come from households, vehicles, and major institutions such as the University of Massachusetts, Amherst College, and Hampshire College. UMass alone produces about as much pollution as all other community emissions combined, making its decisions especially significant for Amherst’s totals.
Stationary energy use in town buildings makes up the biggest portion of municipal emissions. Ordway said those accounts represent 75% of the municipal ledger, and the report also flagged a 70% rise in pumping station emissions without identifying a cause.
The inventory also pointed to ways for local programs to reduce both pollution and utility bills,  including building upgrades, electrification, and home efficiency measures.
Several projects already in progress could improve Amherst’s results in future inventories. Wildwood and Fort River, two of the town’s biggest-polluting school buildings, are being replaced by Amethyst Brook, a new net-zero elementary school, and the renovated and expanded Jones Library is expected to open in 2027 with lower energy use.
The transportation side of municipal operations also showed gains, with emissions down 22.3%. Fire Department emissions increased because of higher call volume and changes in dispatch policy, while the use of hybrid vehicles also affected the totals.
Institutions outside town government will be central to Amherst’s next phase as well. UMass and Amherst College are both working on geothermal projects, but local committee members remain concerned that UMass is not moving away from its central heating plant for existing buildings.
Amherst’s interim climate milestone is expected in 2028, but local officials said the current report already offers a useful reality check.
“Overall, the municipality is doing pretty well, I think,” Ordway said.
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The MV Yampu, a diesel-electric self-loading 11, 000 deadweight tonnage (dwt) Limestone Carrier has begun operations transporting limestone from construction materials company Adbri’s quarry on South Australia’s (SA’s) Yorke Peninsula to Canada Steamship Lines (CSL) subsidiary CSL Australia’s Birkenhead cement manufacturing plant in Adelaide.
An Andorra-based marine energy company AYK Energy 6.7 MWh Aries+S battery system installed on Yampu will recharge at Adbri’s facility, allowing battery operation for the ship approximately 40% of the time.
MV Yampu was built in China for CSL Australia under a contract held by Finland’s technology group Wärtsilä, and forms part of the vessel’s hybrid diesel-electric power system.
Approximately half of the ship’s energy demand comes from shore power and onboard storage, with the system’s design allowing for an upgrade to 100% electric operations in the future.
CSL Chief Executive Officer Louis Martel said MV Yampu represents a significant step forward in the company’s decarbonization journey and demonstrates how practical innovation can deliver real environmental benefits while meeting the demands of commercial operations.
“Every improvement in cargo handling, every enhancement to onboard systems, and every operational innovation has been implemented with one goal in mind: helping our crews perform their work safely, efficiently and sustainably,” Martel said.
“Ultimately, this vessel showcases how smart design can improve performance,” he added. “The Yampu strengthens our supply chain, supports local jobs and demonstrates that reducing emissions and maintaining a strong Australian manufacturing sector can go hand in hand.”
The name Yampu was chosen through an Adbri-wide employee process and comes from the Narungga and Kaurna languages of SA, where it refers to dolphins.
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Our special edition for Intersolar South America 2026 is here!
Discover the latest insights into the Brazilian solar market – in Portuguese.
Entries open in seven categories: Modules, Inverters, BoS, BESS, Manufacturing, Sustainability, Projects.
April 01 – August 31, 2026
A two-day conference in Austin, Texas, bringing together leaders in US solar manufacturing, equipment specification, and factory execution.
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The study measured middle class relative to what people in a given place typically earn.
Photo Credit: iStock
Rising bills for basics such as food and housing have made “middle class” feel harder to pin down for many families.
An income analysis has suggested that the minimum household income to qualify for that status in New York starts at $57,213.
As lohud reported, SmartAsset relied on 2024 one-year American Community Survey data from the U.S. Census Bureau to estimate middle-class earnings in every state and the 100 largest U.S. cities. The company used Pew Research Center’s formula, which defines middle class as households earning between two-thirds and twice a place’s median household income.
Applying that method to New York produced a middle-class band of $57,213 to $171,640, based on a statewide median household income of $85,820.
Want to go solar but not sure who to trust? EnergySage has your back with free and transparent quotes from fully vetted providers in your area.
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SmartAsset’s state comparison placed New York 15th by the median income associated with middle-class status, behind Massachusetts at $104,828 and New Jersey at $104,294.
The numbers shift sharply depending on where people live. In Buffalo, which ranked 98th among the nation’s 100 largest cities, middle-class households earn from $34,807 to $104,422, with a median of $52,211. In New York City, the reported range was $54,152 to $162,456, with a median of $81,228.
For homeowners looking to make their earnings go further, easing monthly bills could help. For example, going solar is one of the best ways to save money on home energy. You can check out EnergySage for free solar panel installation estimates and to compare quotes.
The study measured middle class relative to what people in a given place typically earn, not necessarily what any one family needs to feel financially secure. That helps to explain why New York City’s threshold can still look lower than the statewide cutoff even though the city’s cost of living is famously high.
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To get started, just answer a few questions about your home — no phone number required. Within a day or two, EnergySage will email you the best local options for your needs, and their expert advisers can help you compare quotes and pick a winner.
What that label covers in daily life can include paying for a home, building an emergency cushion, putting money toward retirement, helping support children, and still having room for an occasional vacation.
A salary that stretches much further in Buffalo may feel far tighter in the five boroughs or nearby suburbs, especially once rent or mortgage payments, child care, transportation, and utility bills are taken into account.
Energy spending is one area where some homeowners may be able to lower costs, especially if they plan to stay in the same home for years.
EnergySage’s free services can help make that process easier. With EnergySage’s help, the average person can save up to $10,000 on solar purchases and installations.
💡Go deep on the latest news and trends shaping the residential solar landscape
EnergySage’s solar map also shows the average cost of a home solar panel system on a state-by-state level, along with details on solar panel incentives in each state. Together, these resources can help readers get the best price for rooftop solar panels.
Adding battery storage to a solar setup is one of the best ways to protect your home during outages, save money on energy, and go off-grid. Homeowners who want to learn more can explore EnergySage for information about home battery storage options, including competitive installation estimates.
For many families, it is another reminder that where they live plays a major role in how far their income can actually go.
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China Built a Solar Panel Empire—and May Have Seriously Messed Up Its Birds  Popular Mechanics
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Posted By: Mining.com Staff August 28, 2026
Zinc climbed to its highest level since June 2022 on the London Metal Exchange (LME) as warehouse stockpiles drained to multi-year lows and mine supply cuts tightened the physical market.
LME zinc for cash settlement closed at $4,107 a tonne ($1.86 a lb.) on Thursday, the highest in more than four years and up 55% from a trough of about $2,650 in mid-2025.
Stock in LME warehouses dropped from about 264,000 tonnes in December 2024 to roughly 95,000 tonnes, a 64% drawdown that has left available metal at its lowest since April 2023, Fastmarkets reported. 
However, China is finally beginning to ramp up zinc exports, according to market participants talking to Fastmarkets this week. The catalyst is tied to how imported zinc was about $720 per tonne more expensive than domestic metal in China this week, the widest disadvantage for imports since 2022.
“China has remained a net importer of refined zinc units this year, albeit at significantly weaker levels, as a combination of strong refined zinc output in China and weak domestic demand caused a build-up of inventories in China at the detriment of LME inventories,” BMO Capital Markets reported in a note on Friday. 
“There are now signs that the arbitrage is strong enough to stimulate exports, with one trader interviewed by Fastmarkets suggesting that refined zinc exports could reach around 20,000 tonnes in August,” BMO said. “We expect this to weigh on LME zinc prices, which have climbed to a 4-year high of nearly $3,900 per tonne in recent months.” 
The simultaneous decline in inventory and rise in price shows physical tightness, as the cash settlement price rises while warehouse stock declines because buyers have less to draw on.
The tightness is mostly concentrated in Western warehouses. Shanghai Futures Exchange zinc inventory has risen over the same period that LME stock has drained, Reuters reported. 
HSBC’s Global Commodity Team forecasts a 2.1% year-on-year decline in 2026 to 12.5 million tonnes, due to lower production levels in Latin America. 
JP Morgan expects zinc prices to stay elevated through 2026 as global supply tightens and demand rises, Investing.com reported.
Major zinc producers exposed to the LME price include Teck Resources (TSX: TECK; NYSE: TECK) with a 47% increase, Glencore (LSE: GLEN) with a 46% increase and Nexa Resources (TSX: NEXA) with a 60% increase in shares since January 2026. 
 
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“It has been going up, never went down.”
Photo Credit: iStock
Florida officials have said home insurance premiums are finally starting to ease across much of the state, offering a small sign of relief after years of punishing increases for homeowners.
But for many residents in Palm Beach County and nearby communities, the changes are still too modest to make a meaningful difference in day-to-day finances.
State data from the first half of 2026 showed average property insurance premiums declined in 51 of Florida’s 67 counties, according to WFLX.
Palm Beach, Martin, St. Lucie, Indian River, and Okeechobee were among the counties where premiums fell.
The July 2026 Property Insurance Stability Report compared average premiums from January 2026 with those from July 2026.
Indian River posted one of the larger local changes, dropping 2.7% from $4,453 to $4,334.
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Palm Beach declined 1.4%, from $6,412 to $6,323; Martin fell 1.6%, from $5,993 to $5,899; St. Lucie slipped 0.9%, from $3,522 to $3,491; and Okeechobee decreased 0.6%, from $3,754 to $3,730.
The report pointed to less litigation after state reforms as one reason some insurers have reduced rates.
Even so, the declines are small, and annual premiums in many of those counties still total several thousand dollars.
Palm Beach County Commissioner Gregg Weiss said county commissioners are still hearing regularly from residents who are struggling with high insurance bills.
“One of the big ticket items of living here is the cost of homeowners insurance,” Weiss said.
Weiss also offered his own example of how far some homeowners go to cut costs. He said he dropped wind coverage on his West Palm Beach home and saved tens of thousands of dollars. Losing that protection can leave a homeowner exposed if a major storm hits.
When insurance becomes unaffordable, some homeowners may underinsure their properties, making recovery after disasters more difficult and adding another layer of financial uncertainty to communities already facing growing extreme weather risks.
That helps explain why the new numbers may not feel like a relief. A 0.6% or 1.4% drop may be a welcome change, but it does not erase years of rising premiums or suddenly make coverage affordable for every household.
For residents who have watched insurance costs keep climbing, the state’s figures may not match lived experience. 
“It has been going up, never went down,” Palm Beach County resident Barry Garcia told WFLX.
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The Independent’s journalism is supported by our readers. When you purchase through links on our site, we may earn commission. Why trust us?
Some new plug-in solar kits are rated at 890W, 1,030W or even 1,260W despite Britain’s 800W limit – here’s why they can still comply with the rules
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Plug-in solar panels are now legal in Great Britain, but anyone browsing the first systems to go on sale may have spotted what, on the surface, looks like a contradiction with the government’s new rules for compliance.
The new rules limit plug-in solar to 800W, yet Argos is already selling UKSOL kits labelled 890W, 1,030W and even 1,260W. So how can they be allowed under the new rules?
The answer is that those larger numbers describe the combined generating capacity of the solar panels, while the legal limit applies to the amount of power the system can feed into your home.
Under the government’s new plug-in solar specification, a compliant system can have a maximum apparent AC power output of 800VA – generally presented to consumers as an 800W limit. The plug-in panels have a microinverter built into the system that ensures it can’t supply more than this amount to your household circuit.
Read more: First look at plug-in solar panels
Solar panels generate direct current (DC) electricity, which passes through the system’s microinverter and is converted into alternating current (AC) electricity, which is used by the appliances in your home.
The plug-in solar panels and the inverter therefore have their own separate power ratings.
Take, for example, the £989 UKSOL Pro Max kit currently listed by Argos. It includes two 630W solar panels, giving it a total nominal panel capacity of 1,260W, but those panels feed into an 800W microinverter. No matter how much electricity the panels are capable of producing, the inverter still limits the AC output supplied to the house.
That means a system can legitimately contain more than 800W of solar panel capacity without exceeding the plug-in solar limit.
Read more: Plug-in vs installed solar panels
Your next question is probably: What’s the point, then, of getting panels with more than 800W capacity? It’s a good question. It might sound wasteful, but solar panels rarely produce their headline output on a continuous basis.
A panel’s wattage is measured under standard laboratory test conditions. But in the real world, output varies according to factors such as the time of day, season, cloud cover, temperature, shading and the direction and angle of the panels.
Using a system that’s more than 800W of panel capacity can therefore help an 800W microinverter get closer to its maximum output for more of the day.
Argos, for example, says the oversized 1,260W panel capacity in its UKSOL kit is intended to maximise generation during poorer weather. On a cloudy morning, the panels might collectively produce considerably less than their theoretical maximum, meaning all of that electricity can still pass through the inverter.
When conditions are good enough for the panels to generate more power than the inverter can handle, the inverter simply caps its AC output at its maximum. This is sometimes known as “clipping”.
Read more: Are plug-in solar panels worth buying?
The important figure for shoppers is therefore not necessarily the number printed on the solar panels.
Britain’s new rules allow a compliant plug-in solar product with a maximum apparent power output of 800VA. The government specification defines a plug-in solar product as a complete system including at least one solar panel, a grid-following microinverter, a manufacturer-supplied lead and UK plug, and a mounting system.
So seeing a 1,030W or 1,260W plug-in solar kit doesn’t mean a manufacturer or retailer has found a loophole in the new 800W rules. It simply means the panels have been oversized relative to the inverter. What reaches your household electrical circuit is still capped at 800W.
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LANSING — Michigan has given the go-ahead for a nearly $100 million solar farm in southern Ingham County, the first project to move forward under a 2023 state renewable energy law that shifted approval for such projects from local governments to the Michigan Public Service Commission.
The MPSC agreed to let Chicago-based Ranger Power construct its 90-megawatt Acceleration Solar Project on 870 acres spanning Leslie, Vevay and Onondaga townships in southwest Ingham County. It also OK’d a settlement agreement between the developer, local governments and the state agency, MPSC officials said in its Thursday, Aug. 27, release.
The project will be developed mainly east of College Road and south of Barnes Road in Vevay Township, and also includes parcels in Vevay and Onondaga townships.
The settlement agreement between MPSC, Ranger Power and the three townships establishes requirements for project construction, noise control, vegetative screening, lighting limitations, prompt complaint resolution, financial assurance for decommissioning, limitations on tree clearing, and more.
The agreement also sets limitations on the project’s footprint, which will include 618 fenced acres, and lays out rules for decommissioning including removal of underground infrastructure and restoration of the land for future agriculture use.
It also includes additional funding for township legal expenses, drain maintenance, and local fire personnel and first-responder training. The company agreed to execute a collective bargaining agreement with one or more labor organizations for the project construction and maintenance work to be performed.
“The MPSC and the townships will monitor construction and operation of the project to ensure compliance, with required reports submitted to the Commission and townships,” the commission said in its release. “That includes annual reports on energy production, complaints, maintenance, and financial assurance through the life of the project.”
Ryan Wardin, spokesman for Ranger Power, said construction should begin in the first quarter of 2027 and operations should begin in mid-2028.
Gov. Gretchen Whitmer said in a statement that Michigan is leading the way on the future of clean energy.
“This project will bring tens of millions in investment and more than a hundred good-paying jobs to Michigan communities,” she said. “It’s the very first project sited under the historic clean energy bill package I signed in 2023, which is helping us improve the grid, lower electricity bills, and build, baby, build more solar panels and wind turbines across Michigan.
“Let’s work together to grow our economy, protect our air, land, and water, secure our energy independence, and build a bright future for Michigan.”
Supervisors John Lazet of Vevay Township and Phil Hutchison of Onondaga Township could not be reached for comment.
Dallas Henney, Leslie Township’s supervisor, has been critical of the solar project and said earlier this year the legislation “pretty much took it out of our hands.” So he and the the other supervisors did what they could, Henney told the State Journal on Friday, Aug. 28, to get the best deal for their constituents.
“The process was tedious, which most government processes are,” he said. “Obviously, it was going to happen. It is what it is.”
Ranger Power’s release included a statement from Lazet.
“Following the filing of an application with the MPSC, the Township is grateful that Ranger Power was willing to sit down and listen to the quality of life concerns we had,” Lazet said. “We found Ranger Power to be thorough, detailed, competent, and open to township input. The result being an agreement that we feel is in the best interest ofboth the township and the Project.”
Ranger officials said Acceleration Solar is expected to bring up to $136 million in investment to thecounty and create approximately 150 jobs during construction. There will be a handful of long-term, full-time operations and maintenance positions.
The company said the project will generate substantial tax revenue, with an estimated $8 million going to InghamCounty, $5.1 million to the Ingham Intermediate School District, $4.6 million to local schools, and $7.3 million incombined revenue for township millages.
“Today’s decision demonstrates what can be accomplished when communities, project developers, and state leaders work together toward a shared goal,” said Paul Harris, Ranger Power’s co-founder and president. “We are grateful to the community members and leaders of Vevay, Leslie, and Onondaga townships for their thoughtful engagement throughout this process. Acceleration Solar will deliver significant investment and employment opportunities whilesupporting Michigan’s long-term energy goals to provide the cheapest power available.”
Ranger Power promised in the release to maintain close coordination with the three townships, Ingham County, residents and state officials as Acceleration Solar progresses. This continued engagement is to include regular construction updates, pre-construction coordination and resident input on preferred visual screening.
DESRI, Ranger Power’s New York City-based partner on projects across the upper Midwest, will assume project responsibility at the start of construction and continue community engagement throughout Acceleration Solar’sbuildout and operations.
Ranger Power’s Acceleration Solar application was the first filed with the MPSC after legislators approved Public Act 233. The MSPC’s website shows the agency has granted a certificate for Acceleration Solar and it continues to review six complete applications.
Walker Road Solar Farm LLC has voluntarily withdrawn its application to use about 1,600 acres for a solar farm in Bingham Township, near St. Johns.
MPSC records show Walker Road Solar Farm LLC voluntarily withdrew its application.
In January, local residents crowded the Bingham Township hall to protest and raise concerns about the project that a company official said would produce 150 megawatts of clean energy, which is enough to power about 28,000 homes.
The township board did not have a vote in the matter.
Contact editor Susan Vela at svela@lsj.com or 248-873-7044. Follow her on Twitter @susanvela.

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Energies Media
The Yellow Sea is generating solar power on floating platforms, and seaweed is keeping it steady.
The intermittency and land limitations of traditional photovoltaic installations remain global challenges.
To address this and boost grid stabilization, developers are exploring different deployment methods.
Offshore infrastructure is rapidly becoming more popular, but harsh marine conditions create structural challenges.
Will the latest findings based on the Yellow Sea study help raise floating integrity more naturally?
In the worldwide race to shift toward renewable energy sources, solar power remains in the lead.
The technology is the largest source of installed green capacity globally.
It has pushed the world’s total renewable capacity past 5.1 terawatts.
In one year, over 500 gigawatts were added, driving approximately three-quarters of new clean energy expansion.
Thanks to highly cost-effective production costs and versatility, solar power can be scaled rapidly.
For many nations, photovoltaics have become fundamental in advancing decarbonization.
However, despite its growth milestones, the source still faces a major obstacle.
Traditionally, solar energy faces intermittency, making power generation dependent on daylight and weather conditions.
If this challenge is not addressed, the variable electricity supply fails to stabilize modern electrical grids.
As a result, the addition of massive battery energy storage systems (BESS) has become vital for utility-scale solar facilities.
But even this combination creates challenges for developers.
Beyond requiring millions in financing for large-scale solar developments, these projects also need vast land footprints.
In densely populated nations such as China, this spatial demand can spark immense conflicts.
In these regions, valuable land is often reserved for housing, agriculture, and conservation.
This leaves little to no room for major energy facilities.
On average, these plants require between five and ten acres of land per megawatt.
When giant battery systems are brought into the equation, the land footprint becomes much larger.
Standard 4-hour systems require up to 9 acres of land, making massive solar-battery plants more costly to expand.
While these combinations are key to meeting rising data center demands, developers are exploring other approaches.
The industry has turned to offshore infrastructure, as floating solar power immediately overcomes land limitations.
But as one problem is solved, another one rises.
Harsh marine conditions can compromise structural integrity, but installations on the Yellow Sea found a biological solution.
China is rapidly expanding its floating solar capacity.
Off the coast of Shandong Province, the Yellow Sea is home to the hybrid installation called Yellow Sea No.1.
The 300 megawatt facility consists of wave-resistant floating solar platforms combined with wind turbines.
The Yellow Sea is known for its extreme seasonal weather, monsoons, and harsh conditions.
This marine environment tests the limits of the floating infrastructure.
However, recent research revealed a surprising notion.
Underneath the panels, seaweed flourished along with other marine life.
This natural growth beneath the platforms created a beneficial dampening effect.
The more the seaweed grew, the bigger the drag it generated.
This drag significantly reduced the impact of wave motion, keeping the structures remarkably steady in the water.
Consequently, the seaweed served as a biological solution to the extreme physical stresses experienced in open marine environments.
Presently, the Yellow Sea No.1 project continues to generate clean energy.
The study’s findings demonstrate the value in exploiting natural marine growth as structural reinforcements.
Key suggestions include intentionally cultivating compatible seaweed species beneath floating platforms.
This will help future projects save engineering costs while boosting structural resilience.
Ultimately, it can help accelerate sustainable offshore capacity growth worldwide, but it is vital to monitor potential risks of biofouling.
You can review the study using the APA CITE: Zhang, P., Qi, X., Cheng, Z., Zhao, Y., Li, J., Zhang, L., … & Ding, H. (2025). Field trial research of a semisubmersible floating photovoltaic platform. Solar Energy, 301, 113982.
Anke Maree is a writer with a clear and engaging editorial style. Her work focuses on making complex topics accessible, informative, and relevant for readers across different areas of interest.
Anke Maree is a writer with a clear and engaging editorial style. Her work focuses on making complex topics accessible, informative, and relevant for readers across different areas of interest.
Anke Maree is a writer with a clear and engaging editorial style. Her work focuses on making complex topics accessible, informative, and relevant for readers across different areas of interest.

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How can plug-in solar kits be 1,260W when the limit is 800W?  AOL.com
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Perovskite solar cells have long promised a cheaper, more versatile alternative to conventional silicon photovoltaics, yet the manufacturing methods needed to turn that promise into mass-produced devices remain stubbornly difficult. A new study reports a way to produce fully screen-printed perovskite solar cells in ordinary air while improving both their efficiency and operational stability. The devices achieved a power conversion efficiency of 22.41%, with an independently certified efficiency of 21.86%. They also retained more than 90.5% of their initial performance after 2,000 hours of accelerated light-soaking, and showed no degradation after 900 hours of operation at 85 °C and 50% ± 10% relative humidity. The results point to a manufacturing strategy that tackles one of the least visible but most consequential problems in perovskite photovoltaics: how liquid precursor materials move and crystallize inside thick, multilayered films.
Perovskites are a family of crystalline materials whose electronic properties can be tuned through their chemical composition. In solar cells, they absorb sunlight efficiently and generate mobile charge carriers, making them attractive for lightweight, flexible and potentially low-cost photovoltaic technologies. Screen printing could make these devices especially scalable because it deposits functional materials through patterned meshes, much like industrial printing processes. In a fully screen-printed architecture, multiple layers can be deposited sequentially, including the charge-transporting components, the perovskite absorber and the carbon electrode. The approach reduces reliance on vacuum equipment and could simplify manufacturing. But thick printed layers create a difficult physical environment for crystallization. A precursor solution must penetrate downward through the porous structure, react and solidify in the correct sequence, and form a continuous semiconductor without leaving voids, defects or mechanical stress behind.
The researchers identify inefficient vertical phase transformation as a central obstacle. During fabrication, the liquid perovskite precursor must undergo a transition from a solution containing dissolved and dispersed chemical components into an ordered crystalline solid. If crystallization begins too early at the surface, a crust can form before the underlying material has been fully infiltrated. That premature surface nucleation blocks further penetration and leaves the lower portions of the film poorly converted. Incomplete infiltration can create disconnected regions, while uneven crystallization generates defects that trap charge carriers. Residual stress may also accumulate as the material shrinks or rearranges during solidification. Each of these problems can reduce the current extracted from the cell and increase recombination, a process in which electrons and holes meet before they can do useful work in an external circuit. In thick printed films, controlling the path and timing of the liquid is therefore as important as controlling the final crystal chemistry.
To address the problem, the team developed what it calls a fluid motion crystallization strategy. The method uses a co-solvent system composed of the ionic liquid methylammonium propionate and butyronitrile. Ionic liquids are salts that remain liquid under relatively mild conditions and can strongly interact with precursor species, while butyronitrile is used here to alter how the precursor solution flows and solvates its ingredients. According to the study, butyronitrile reduces the resistance to fluid motion and helps disperse aggregates of lead iodide, a key precursor component. The result is an optimized solvation structure: rather than allowing large or poorly dispersed precursor clusters to impede movement, the liquid remains sufficiently mobile to travel rapidly and deeply into the printed film. This fluid-control step is crucial because it shifts crystallization from a surface-dominated event to a more coordinated transformation throughout the film’s depth.
The proposed mechanism begins with rapid, deep infiltration of the precursor into the multilayered structure. Once the liquid has reached the lower regions, the material undergoes a bottom-up, ordered phase transition. In practical terms, crystallization starts in the interior or lower portion of the film and progresses upward before a competing crystalline layer can form at the exposed surface. This sequence helps the entire precursor volume participate in the conversion, reducing the likelihood of unfilled pockets and poorly connected grains. It also suppresses the formation of defects associated with abrupt or incomplete solidification. The importance of this ordering lies in the fact that a solar-cell absorber is not simply a layer of light-absorbing material; it must also provide a continuous route for photogenerated charges to reach the electrodes. A film that appears visually complete can still contain microscopic barriers that cause electrical losses if its crystals are poorly connected or riddled with defect sites.
After the controlled phase transition, the researchers observed the growth of a dense, interconnected network of perovskite nanocrystals. Nanocrystals are crystalline domains measured on the nanometre scale, and their connectivity determines how efficiently charges can move through the absorber. The reported network is accompanied by an island-like surface morphology rather than an entirely flat interface. That morphology strengthens contact between the perovskite and the carbon electrode deposited above it. The interface is a critical region in a printed solar cell: photogenerated electrons and holes must be transferred across it without becoming trapped or recombining. Intimate physical contact can lower interfacial resistance and provide more direct pathways for charge extraction. By combining a compact internal crystal network with a better-connected surface, the strategy appears to address two linked sources of loss—poor transport through the absorber and recombination near the electrode boundary.
The performance figures suggest that the processing method does more than improve an isolated laboratory measurement. The air-processed, fully screen-printed cells reached 22.41% power conversion efficiency, meaning that fraction of incident solar power was converted into electrical power under the reported testing conditions. The certified value of 21.86% is particularly significant because certification provides an independent assessment of the device’s measured output. Efficiency alone, however, is an incomplete measure of photovoltaic progress. Perovskite materials have historically faced concerns over long-term stability, with heat, light, moisture and electrical operation all capable of accelerating degradation. In this study, the devices preserved over 90.5% of their starting efficiency after 2,000 hours under ISOS-L-1 accelerated light-soaking conditions. They also showed no degradation after 900 hours at 85 °C and 50% ± 10% relative humidity under the ISOS-L-3 operational protocol, combining elevated temperature, moisture and continuous operation.
Those durability results are closely connected to the film’s microscopic structure. Defects and voids can act as chemical and electrical weak points, allowing moisture or heat to trigger local deterioration and creating pathways for further damage. Residual stress can have a similar effect by making the film more vulnerable to cracking or interfacial failure during thermal cycling. A dense, interconnected nanocrystal network may limit these vulnerabilities, while stronger contact with the carbon electrode can help preserve the electrical connection as the device operates. The study does not present stability as a separate coating or after-treatment solution; instead, it links durability to how the precursor flows and crystallizes during fabrication. That is an important shift in emphasis. Controlling the earliest stages of film formation may prevent the structural imperfections that later become visible as efficiency losses, rather than attempting to repair them after the solar cell has already been built.
The work also illustrates why manufacturing physics can determine whether an emerging photovoltaic technology remains a laboratory curiosity or becomes an industrial contender. Perovskite absorbers can be deposited at relatively low temperatures and are compatible with solution-based processing, but those advantages are realized only if the liquid precursor can be controlled across large areas and through multiple layers. Screen printing offers a potentially high-throughput route, yet its patterned deposition process naturally creates films whose thickness and porosity must be managed during conversion. A co-solvent that tunes fluid resistance, precursor aggregation and the order of crystallization could therefore be valuable beyond the specific devices tested in this study. The reported approach is not merely an adjustment to the final electrode or a small optimization of a laboratory coating; it targets the coupled relationship between fluid dynamics, chemical solvation, nucleation and charge transport. That integrated control is what makes the result potentially relevant to scalable production.
The researchers’ results do not eliminate every challenge facing perovskite solar technology, and the reported tests do not by themselves establish how the cells would perform over many years outdoors or across industrial-scale modules. Nevertheless, the combination of air processing, full screen printing, certified efficiency above 21%, and strong resistance to demanding light, heat and humidity tests gives the strategy unusual news value. The core insight is both technically specific and broadly understandable: in a thick printed solar cell, the route taken by a liquid before it becomes a crystal can determine how well the finished device works. By making the precursor more mobile, dispersing lead iodide aggregates and forcing crystallization to proceed from the bottom upward, the team created a more continuous absorber and a more effective carbon interface. The result is a perovskite solar cell designed not only to capture sunlight efficiently, but also to survive the physical stresses imposed by practical operation.
Subject of Research: Air-processed, fully screen-printed perovskite solar cells using fluid motion and crystallization control
Article Title: Fluid motion and crystallization control enable air-processed fully screen-printed perovskite solar cells
Article References: Chen, C., Yao, Q., Ding, Y., et al. (2026). Fluid motion and crystallization control enable air-processed fully screen-printed perovskite solar cells. Nature Photonics. https://doi.org/10.1038/s41566-026-01991-3
Image Credits: AI Generated
DOI: https://doi.org/10.1038/s41566-026-01991-3
Keywords: perovskite solar cells, screen printing, crystallization control, fluid motion, photovoltaic manufacturing, carbon electrodes, charge transport, solar-cell stability
Tags: Air-processed perovskite fabricationCrystallization behavior in multilayer perovskite filmsCrystallization control in thin-film photovoltaicsFluid dynamics in perovskite crystallizationFully screen-printed perovskite solar cellsImproving efficiency and stability of perovskite photovoltaicsLong-term operational stability of perovskite solar devicesLow-cost manufacturing techniquesPerovskite solar cell manufacturingScalability of perovskite solar cell production
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Given the price of gas these days, electric vehicles sound like an affordable alternative. However, what you save on gasoline you will likely spend on higher electricity bills and registration fees. You might try to mitigate these costs by charging your electric vehicle with solar panels, but Chinese automakers have a more portable idea.
Recently, the company Fuyao Group, one of China’s leading suppliers of glass for cars (windshields, side windows, etc.), announced it is ready to mass produce “photovoltaic sunroofs” that can charge cars as they drive. The name isn’t wordplay or anything — Fuyao didn’t develop solar panels that are installed on the roof to soak up the power of the sun. Instead, the company designed laminated glass panels (i.e., actual sunroofs) with embedded solar cells. Unlike perovskite panels that go on top of existing windows, Fuyao’s photovoltaic glass is designed to fit vehicles sold by BYD Auto, specifically its Han and Tang models, for an additional installation fee.
According to various solar industry reports, Fuyao Group has been working closely with BYD Auto for several years on the photovoltaic sunroofs. Fuyao previously told investors that it could begin production as early as 2024 and could increase production by 2026.
While the technology behind Fuyao Group’s photovoltaic sunroofs sounds promising, the news of its development has spurred several rumors about its capabilities. People who are expecting these photovoltaic sunroofs to revolutionize the electric vehicle industry might have to temper their expectations.
Those same industry reports note that the output of Fuyao’s photovoltaic sunroofs tops out at around 720 watts, which is a drop in the bucket compared to what EVs generally need. While driving on highways, electric cars require tens of kilowatts to keep the vehicle moving at a steady speed. Then again, the energy from these sunroofs is mainly intended for onboard electric equipment, which at the very least can free up battery power for the engine and squeeze out a few more miles during long trips. However, neither Fuyao nor BYD Auto published these reports. The companies haven’t even provided any technical specifications or pricing estimates, so it’s anyone’s guess as to how much energy or long-term savings the components will actually provide.
If Fuyao Group’s sunroofs live up to expectations, we can add them to our list of reasons why Chinese EVs should be sold in the US. Or, at the very least, Fuyao could license out production schematics to local car manufacturers. Who wouldn’t want to buy an add-on that pays for itself in charging cost savings over the long term?
Fuyao Group is not the first car company to offer photovoltaic sunroofs. Toyota has been selling solar roofs as an add-on for its Prius Prime (specifically the XSE Premium trim) for several years. However, just because two companies have the same (or similar) ideas doesn’t mean the concepts are executed in identical fashion.
The first major difference is the types of cars that use these solar roofs. Whereas the BYD cars designed to use the add-on, the Han and Tang, are fully electric, the Prius Prime is a plug-in hybrid. You still need to fill the tank with gas, but you technically get more miles to the gallon thanks to the electric motor.
While Fuyao’s glass only supplements dashboard electronics, the company states the photovoltaic sunroof provides a constant supply of electricity, which implies the vehicle charges while in motion. Meanwhile, Prius Prime owners state their car’s solar roof really only charges the vehicle while it’s parked, ideally in direct sunlight. However, while both the BYDs’ and Prius Prime’s photovoltaic sunroofs can power auxiliary systems, Prius owners are split when it comes to usefulness. Some think the roof helps their commutes, while others believe it is borderline useless. We can’t rely on owner feedback on Fuyao Group’s solar glass roofs since they aren’t widely available yet, but time will tell if they’re an improvement over Toyota’s version.

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The current draft reflects an attempt to balance access and oversight for small clean energy projects.
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After several years of local discussion, Amherst, Massachusetts, may soon formalize standards for smaller solar arrays and battery systems, an effort aimed at allowing more clean energy development without threatening drinking water.
If approved, the measure could make it easier for local property owners to install money-saving energy systems while setting clearer safeguards for wells, farmland, and wildlife.
Amherst’s proposed Small Clean Energy Infrastructure Bylaw, a 19-page measure, has cleared its first reading before the Town Council, according to the Daily Hampshire Gazette.
Councilors are expected to revisit it for a second reading and possible vote on September 14.
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District 4 councilor Pam Rooney, who chairs the Community Resources Committee, said the proposal is designed to bring Amherst into line with state law through one consolidated permit process and provide clear siting rules for solar arrays and battery storage systems.
The measure comes after more than four years of work, including efforts launched by the Solar Bylaw Working Group in March 2022 and recommendations finalized in August by the Planning Board and Community Resources Committee.
Going solar is one of the best ways to save money on home energy over time. Homeowners curious about the numbers can explore EnergySage to get free solar installation estimates and compare quotes.
Questions during the discussion centered on whether the proposal does enough to protect nearby residents.
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District 2 councilor Lynn Griesemer noted roughly 5% of Amherst residents use private wells and asked whether those wells deserve the same 200-foot no-disturbance buffer applied to other water sources.
She also questioned whether the town should require ongoing inspections once solar installations and battery systems are up and running, along with hazardous-waste insurance to cover damage caused by storms or other disasters.
Environmental impacts to animals came up as well. District 5 councilor Ana Devlin Gauthier argued the draft gives wildlife only a “passing glance” and said it should say more about migration corridors, bird-friendly glare reduction, and fence designs that limit harm.
Town Council president Mandi Jo Hanneke responded that the bylaw’s Site Suitability Score already covers mitigation and biodiversity.
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The current draft reflects an attempt to balance access and oversight for small clean energy projects. It spells out siting, operating, and removal expectations, and Rooney said it also adds larger setbacks from wells and permits agrivoltaics, which place solar panels over active farmland.
For homeowners beyond Amherst, tools that clarify the cost of renewable energy can be just as important as rules that clarify permitting. EnergySage’s free services can help people compare options with less guesswork, including EnergySage’s solar map to research average costs by state. Together, those resources can help readers get the best price for rooftop solar panels and access available incentives.
Adding battery storage to a solar setup is one of the best ways to protect your home during outages, save money on energy, and go off-grid. Homeowners interested in backup power can explore EnergySage for information about home battery storage options.
“In a nutshell, this document represents the town of Amherst’s adaptation of the state mandate to have and allow a single consolidated permit available for applicants starting October 1,” Rooney said.
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Global investment in renewable energy reached $327.5 billion (€281 billion) in the first half of 2026, virtually unchanged from the previous six months but 21% below the record set in the second half of 2024.
Data from BloombergNEF (BNEF) show that renewable energy deployment remains on track despite regulatory changes in key markets, including the United States and China. Investment, however, is increasingly shifting toward assets that offer greater flexibility in managing revenues.
Financing for standalone utility-scale solar fell more sharply than investment in onshore wind. Investment in standalone solar PV declined 20% year on year to $75.4 billion (€64.7 billion), its lowest level since the solar investment boom began in 2021.
Growing revenue uncertainty, driven by solar price cannibalization, curtailment and grid congestion, is pushing investors and developers toward more flexible project configurations.
Against this backdrop, co-located solar-plus-storage projects attracted a record $25 billion (€21.5 billion) in investment in the first half of 2026. The figure was nearly double the total recorded in the second half of 2025 and three times the amount invested in the first half of that year. The United States and Australia led investment in the segment.
The United States was the second-largest market for renewable energy investment, behind China but ahead of the European Union, recording 54% year-on-year growth. Developers accelerated project financing to meet tax credit deadlines and respond to surging electricity demand, driven in part by data centers.
Solar investment rose 41% to a record $45.8 billion (€39.3 billion), while wind investment reached $13.8 billion, more than double the previous year’s figure. Projects that remain eligible for tax credits could sustain construction activity in the short term, with the final installations scheduled through 2030.
Global wind investment totaled $92.3 billion, down 27% year on year. Offshore wind was particularly hard hit, with investment plunging 72% amid poor auction results, higher capital and financing costs and a shrinking pipeline of projects likely to reach financial close.
Onshore wind investment declined by a more moderate 4% to $80.7 billion. Europe, however, bucked the trend, with Germany, Romania and Serbia all recording record investment levels following recent auctions.
China accounted for just one-quarter of global investment, down from more than half in 2022, following reforms to its electricity market. By contrast, Vietnam quadrupled its investment, while investment across Southeast Asia surpassed $12 billion. Nigeria increased investment in distributed solar and storage, Central Asia maintained investment above $4 billion, and Brazil helped push global biofuel investment to $7.7 billion.
BloombergNEF expects new renewable energy installations in 2026 to fall below 2025 levels, marking the first year-on-year decline in more than a decade. It expects growth to resume in 2027.

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For two decades, the solar EV sector’s core problem wasn’t panels — it was physics. Bolt solar panels onto a two-ton SUV that burns 350 watt-hours per mile, and a full day of Southern California sun barely adds ten miles of range. The panels were never the issue. The math was wrong. Now, for the first time, an independent testing organization has confirmed that a production-stage solar EV is solving the math correctly.
TÜV Rheinland, the German testing and certification firm founded in 1872, dispatched a solar specialist to Aptera’s Carlsbad, California headquarters for three days of on-site measurements in July 2026. The firm confirmed that the company’s Atlas vehicle generates 4.23 to 4.75 kWh of usable energy from its solar panels per day — enough, at Aptera’s claimed efficiency of roughly 100 watt-hours per mile, to cover 42 to 47 miles of driving entirely on sunlight. According to DOE household travel survey data, the average American in a one-vehicle household drives approximately 30 miles daily, meaning a fully parked Aptera in a sunny region could go weeks without touching a charging cable.
That result matters because solar EVs have been promising this outcome for years and failing to deliver it — not because of bad engineering, but because no prior solar vehicle was efficient enough for the panel output to matter.
This is not a panel spec sheet figure. That distinction is the heart of what makes this verification unusual.
Dr. Giorgio Bardizza, a solar specialist at TÜV Rheinland, wired sensors to each string — calibrated data loggers recording current, voltage, and power across each individual solar string on the vehicle’s body. His team simultaneously monitored the high-voltage bus feeding the battery pack. The verified figures represent energy delivered to the battery after conversion losses — not the raw output printed on a manufacturer’s spec sheet, and not what the panels could theoretically produce under laboratory conditions.
The technical reason this matters: Aptera’s solar charge controller uses Maximum Power Point Tracking, or MPPT, a real-time optimization system that continuously adjusts its operating point to extract the maximum available power from each string as sun angle, cell temperature, and shading vary throughout the day. Because the Atlas’s teardrop body wraps solar cells at dozens of different angles simultaneously, each string operates at a different optimal point at any given moment. A single measurement point would miss this complexity; per-string monitoring captures it.
In addition, the solar cells operate at relatively low voltage; the battery pack operates at approximately 400 volts. A boost converter steps up voltage, losing a small percentage of energy in the process. TÜV measured energy entering the battery after that conversion — the number that actually matters for range.
The three test days were structured differently to model distinct real-world conditions:
The day one figure is the one a prospective buyer should care about. Park the car, walk away, and it still clears Aptera’s stated 40-mile daily solar target without a single adjustment.
“The most exciting result is the day we simply parked the vehicle in the sun and let it do the work,” said Steve Fambro, Aptera’s co-founder and co-CEO.
“When American innovation turns sunlight into miles, independent testing helps turn that promise into confidence,” said Jonathan Kotrba, VP of Products at TÜV Rheinland.
Aptera has made its full TÜV Rheinland test report publicly available for download on its website.
Here is the arithmetic that prior solar EVs could not clear.
A conventional electric SUV consumes 300 to 400 Wh/mile. At 400 Wh/mile, a full day of verified solar output — 4.23 kWh — delivers just 10.6 miles. At Aptera’s target of approximately 100 Wh/mile, the same 4.23 kWh delivers 42.3 miles. The panel output is identical. The mileage is four times higher. Efficiency is the multiplier; panels are just the input.
The Atlas achieves that efficiency target through three specific engineering choices. First, a teardrop aerodynamic body produces a coefficient of drag of 0.13 — roughly half the drag coefficient of a typical modern sedan and about one-third that of popular electric crossovers. Second, the vehicle’s structure uses carbon fiber and fiberglass composite construction, bringing the 44 kWh Launch Edition to a curb weight of 998 kg (2,200 lbs) — less than half the weight of most electric crossovers and comparable to some small European city cars. Third, because the vehicle is classified as a three-wheel motorcycle under US federal regulations rather than as a passenger car, it operates under a different regulatory envelope that permits the structural and design choices that make that weight possible.
The solar cells themselves are supplied by Maxeon Solar Technologies, using Maxeon’s Interdigitated Back Contact (IBC) cell architecture. IBC cells place all electrical contacts on the rear surface of the cell, maximizing the active light-capturing area. Maxeon’s IBC panels achieve module efficiencies of 23% to 24% — roughly 20% higher than conventional mono-PERC panels per square meter. For a vehicle body with more than three square meters (approximately 32 square feet) of curved surface area, that efficiency premium adds meaningfully to total output. The 700 watts of installed solar capacity on the Atlas reflects approximately 220 watts per square meter of effective area, consistent with IBC-class performance.
One supply-chain note: Maxeon Solar Technologies entered its own restructuring proceedings in Singapore in 2026. The current status of Aptera’s supply agreement with Maxeon under that process has not been publicly confirmed, and represents an operational risk the company has not publicly addressed in detail.
The verification arrives at a moment when the sector’s credibility has been tested by high-profile failures.
Lightyear, the Dutch startup that grew out of the student team that built the record-setting Stella Lux solar car, raised substantial investment and accumulated more than 21,000 pre-orders from fleet operators for its Lightyear 2 solar EV. The company declared bankruptcy in January 2023, just two weeks after opening that waiting list. A restructured entity subsequently emerged, but the episode rattled confidence across the category.
Sono Motors, a German startup, drew approximately 21,000 reservations for its Sion solar EV before canceling the Sion in February 2023, laying off 300 employees, and pivoting to selling its solar integration technology to commercial vehicle manufacturers. The Sion was a conventionally sized and weighted hatchback — at roughly 1,400 kg (3,086 lbs) and planned to consume roughly the same energy per mile as any other small EV, its solar roof was always going to deliver modest range supplementation at best.
That is the structural difference. Both Lightyear and Sono attempted to make solar work at conventional vehicle weights and consumption levels. Aptera’s efficiency advantage doesn’t just make solar output look better — it makes a fundamentally different product category possible.
Aptera Motors (Nasdaq: SEV) built its first validation vehicle off the assembly line in March 2026, at its Carlsbad facility. The 14-station line marked the transition from hand-built prototypes to a repeatable assembly process. The company is targeting delivery of its first 40 production vehicles in the fourth quarter of 2026 through its Launch Design manufacturing partnership.
Aptera listed on Nasdaq in October 2025 under the ticker SEV, having raised more than $145 million in total funding through equity offerings and community investment rounds. However, the company’s 2025 annual filing with the SEC requires additional capital — an additional $45 million to $50 million — to complete vehicle validation and prepare for low-volume production. Battery options range from 25 kWh to 100 kWh, with claimed EPA ranges of 250 to 1,000 miles from plug-in charging via a NACS (Tesla-compatible) connector at up to 50 kW DC. Full-scale production is planned for 2028, pending additional funding.
The TÜV Rheinland verification establishes an independently measured baseline ahead of that production ramp. No production-stage solar EV had previously received this level of independent daily output verification. If Aptera reaches meaningful volume, TÜV Rheinland’s measurement methodology — per-string monitoring plus high-voltage bus confirmation, measuring energy delivered to the battery after conversion losses — could become a reference standard for how the industry evaluates solar charging claims, much as EPA range testing established a common baseline for battery range comparisons.
The parked-car number — 4.23 kWh delivered to the battery without anyone touching the vehicle — is the figure the solar EV sector has been trying to produce for the better part of two decades. For Aptera, an independent auditor now says it’s real.
The verified output numbers apply to optimal Southern California sun conditions in July, tested at Aptera’s Carlsbad headquarters. Drivers in cloudier climates, higher latitudes, or winter months will see proportionally lower figures. Aptera’s own in-house data shows the vehicle consistently produced 3.6 to 4.6 kWh across varied real-world weather conditions at its Carlsbad test site. The technology is real; the location math is on the buyer to calculate.
TÜV Rheinland independently measured 4.23 kWh of daily solar output under normal parked conditions (no adjustments, hatch closed) at Aptera’s Carlsbad, California facility during July 2026 on-site testing. At Aptera’s claimed 100 watt-hours per mile of energy consumption, that translates to approximately 42 miles of range from solar alone. With a single mid-day repositioning of the vehicle and the hatch raised, the figure rises to 4.75 kWh, or about 47 miles.
Prior solar EV programs failed for two reasons: funding and physics. On the physics side, Lightyear and Sono were building vehicles with conventional weights (Sono’s Sion weighed about 1,400 kg, or 3,086 lbs) and conventional energy consumption (roughly 200–300 watt-hours per mile). At those numbers, even excellent daily solar output produces only modest range supplementation — not enough to eliminate the need for regular charging. Aptera’s approach reduces consumption to approximately 100 watt-hours per mile through radical aerodynamics and lightweight composite construction, making the same panel output worth three to four times as much range. That efficiency multiplier is what changes the solar EV equation. Sono Motors canceled the Sion in February 2023; Lightyear’s parent company collapsed that same month.
TÜV Rheinland, founded in 1872, is a German testing and certification organization widely recognized as an independent standard-setter for automotive safety and technical compliance. Its significance here is specific: the firm measured energy delivered to the battery pack after conversion losses, not the raw panel output that a manufacturer would print on a spec sheet. That distinction makes the verified figures directly usable as real-world range estimates rather than theoretical maximums. No production-stage solar EV had received this type of independent daily output verification before Aptera.
Solar output varies with latitude, season, and local climate. The TÜV Rheinland figures were measured in Carlsbad, California, in July — close to peak solar conditions for North America. Southern states including Arizona, Texas, New Mexico, Nevada, and Florida receive enough annual sun hours that the verified solar range would remain close to the tested figures for much of the year. Northern states and the Pacific Northwest will see materially lower output, especially in winter. Aptera’s own Carlsbad solar generation data showed consistent output between 3.6 and 4.6 kWh across varied weather conditions, including overcast days. Buyers should calculate their specific region’s average daily solar hours before treating the 42-mile figure as typical for their area.
ⓒ 2026 TECHTIMES.com All rights reserved. Do not reproduce without permission.

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“It is definitely getting warmer and I feel like summer is just shifting to be later and later now.”
Photo Credit: iStock
The Santa Barbara City Council has received a two-year climate progress report outlining how the city plans to reach carbon neutrality by 2035.
Major strategies include more home solar, more battery storage, more electrification, and a bigger push to shift electricity use away from peak-demand hours.
City leaders said those steps are central to cutting pollution while making everyday energy use cleaner and more resilient.
Santa Barbara’s 2035 carbon-neutrality target was the focus of a two-year update delivered to the City Council by Jefferson Litten, the city’s Energy and Climate Division manager, as KEYT reported. Work is underway across city departments to move that goal forward.
Adopted in July 2024, the Climate Action Plan serves as the city’s guide for that effort. The report said Santa Barbara’s biggest sources of polluting gas are on-road passenger travel and energy use in buildings.
“The city has a really ambitious climate action plan goal of reaching carbon neutrality by 2035,” he said. “So that is going to be a combination of adding EV charging, converting our buildings to electric buildings and adding solar storage wherever we can.”
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Highlighted programs include home electrification, EV charging for both residents and city operations, and tree-related efforts, the report said.
Buildings that switch from gas-powered appliances to electric systems can help reduce indoor air pollution, while rooftop solar and batteries can give households more control over energy bills and help keep the power on during outages or periods of grid stress.
The city is also emphasizing off-peak electricity use, a strategy that can ease pressure on the grid when demand surges.
In practice, that can mean encouraging households to charge batteries or vehicles and run major appliances during lower-demand hours, which may also line up with cheaper utility rates.
Transportation remains another major piece of the equation. Replacing gas-powered vehicles with EVs, alongside expanding bike and pedestrian infrastructure, could help curb tailpipe pollution that contributes to both planet-warming pollution and local air quality concerns. 
Hotter weather is part of the backdrop for the issue. At the State Street farmers market, visitor Jenna Davis connected the city’s planning to what local families are already feeling. 
“It is always changing, it is definitely getting warmer and I feel like summer is just shifting to be later and later now, so kids are going back to school, but it is going to be hot at their school, and in the classroom,” she said.
The city expects to put significant emphasis on solar and on electrifying municipal buildings. The effort isn’t limited to government sites, though, and also includes exploring ways to help residents shift to cleaner energy systems at home.
The report’s actions include incentives for residential solar and battery installations, plus measures meant to move more electricity use into off-peak periods.
Santa Barbara is weighing a student climate innovation grant contest as well as potential partnerships with UC Santa Barbara and Santa Barbara City College.
“The presentation was really well received by council, it was great to see praise for the department and our other departmental partners for all the work we have been trying to do to advance our climate goals,” Litten said.
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LUXEMBOURG, Aug. 28, 2026 /CNW/ — Westbridge Renewable Energy S.A. (WEB) (OTCQX: WEGYF) (FRA: PUQ) ("Westbridge" or the "Company") is pleased to announce that it has entered into a definitive share purchase agreement dated August 27, 2026 (the "Agreement") for the sale of its Red Willow solar-plus-storage project in Alberta (the "Transaction"), through the sale of all of the issued and outstanding shares of its wholly-owned subsidiary, Red Willow Solar Inc. ("Red Willow").
Summary of key terms
Red Willow is an advanced-stage, utility scale solar-plus-storage project comprising a solar power plant of up to 225 MWac and a proposed 100 MW battery energy storage system, located in Stettler County No. 6 in central Alberta. The project's power plant and battery energy storage system have received power plant and substation approvals from the Alberta Utilities Commission (AUC), and the project holds an interconnection position in the Alberta Electric System Operator (AESO) process.
Under the terms of the agreement, Westbridge will receive an upfront cash payment at closing, together with additional milestone payments. The total receivables should reach CAD $26.725m, if all the conditions in the agreement are met, comprising the following milestone payments:
The transaction is subject to customary closing conditions, including regulatory approvals and other conditions precedent. No finder's fees are payable in connection with the Transaction, and the Transaction is an arm's length transaction.
The transaction represents another significant milestone in Westbridge's strategy of originating, developing and de-risking high-quality renewable energy and energy storage infrastructure projects while maintaining a diversified development pipeline across North America and Europe.
Stefano Romanin, Chief Executive Officer of Westbridge, commented:
"The sale of Red Willow represents another important validation of Westbridge's development and monetization strategy. Since establishing our Alberta platform, we have focused on siting projects in favorable locations with strong renewable resources, transmission access and long-term strategic value. Red Willow is an excellent example of that approach, and this transaction demonstrates continued demand for well-positioned renewable energy and energy storage assets. We remain focused on creating value by developing high-quality projects across our international portfolio."
Improving Fundamentals and greater certainty for Alberta's Renewable Energy Market under the Canada-Alberta TIER agreement
On May 15, 2026, Canada and Alberta finalized an Implementation Agreement establishing a long-term trajectory for Alberta's Technology Innovation and Emissions Reduction system through 2040.2 The framework maintains a carbon price of $95 per tonne in 2026, rising to $100 per tonne in 2027, $130 per tonne by 2035 and $140 per tonne by 2040. It also introduces a regulated minimum price for carbon credits beginning at $60 per tonne in 2030 and increasing to $110 per tonne by 2040.
Potential electricity demand from large loads and data centres
At the same time, prospective large-load transmission-service requests reported by the AESO have exceeded 16 GW, compared with Alberta's current system peak of approximately 12 GW.3 If this prospective demand is ultimately developed and connected, it could contribute to firmer electricity prices and improve the economics of new generation in the province. Solar generation paired with battery storage may have a role in supplying this additional demand alongside firm generation sources. Actual outcomes will depend on regulatory decisions, connection capacity and the timing and scale of the proposed developments.
Westbridge's Alberta advantage
Westbridge is an active independent developer of utility-scale solar and battery energy storage in Alberta, with an advanced-stage portfolio in the province. Highlights include:
With approved and interconnection-stage solar and storage assets in the province, Westbridge believes it is well positioned to respond when PPA demand returns, offering competitively priced, clean electricity.
The AI Infrastructure Boom Is Reshaping U.S. Power Demand
The rapid expansion of AI computing has made electricity a central constraint on how quickly the sector can grow. Renewables and solar paired with battery storage in particular are increasingly central to how AI infrastructure is powered. This shift is already visible in the market. Over the past year, hyperscalers have signed a series of large solar and battery-storage power purchase agreements (PPAs), particularly in Texas, converting AI-driven demand into contracted offtake for new renewable projects. Publicly reported examples include:4
Westbridge's U.S. positioning
This demand is being met by a rapid acceleration in U.S. renewable deployment. The U.S. Energy Information Administration (EIA) forecasts that 2026 will be a record year for new electricity capacity, with solar and battery storage the primary drivers. Approximately 86 GW of new utility-scale generating capacity is expected to be added in 2026, the largest single-year increase since 2002. Solar is projected to lead with a record of approximately 43 GW, up roughly 60% year-over-year. Battery energy storage is projected to reach a record of approximately 24 GW, while wind is expected to more than double to approximately 12 GW.
Solar and battery storage, the core technologies in Westbridge's development portfolio, support this build-out, reflecting their competitive cost and their ability to deliver the firm, round-the-clock power that AI and data-centre loads require. These figures are EIA forecasts and remain subject to change. 5
In the United States, the Company holds a strategic development portfolio, including:
This positions Westbridge as a developer, in the clean-power infrastructure the U.S. AI build-out requires.
Spotlight: Southern Prairie, Louisiana6
Among the Company's U.S. projects is Southern Prairie, a 200 MWac solar photovoltaic project paired with a 55 MW battery energy storage system in Calcasieu Parish, Louisiana. The project has secured site control, completed initial environmental studies and selected a point of interconnection. Southern Prairie is located in Louisiana, a state experiencing significant growth in industrial, manufacturing and data-centre-related electricity demand, positioning the type of low-carbon capacity the Company develops in proximity to new demand.
Stefano Romanin, CEO of Westbridge, commented:  "The defining constraint on AI is increasingly power, and the fastest way to add generation capacity in many U.S. markets is utility-scale solar paired with storage. We have spent years building a development portfolio across the United States, including in states where data-centre demand is growing quickly, and we believe that positions us to help supply the clean, reliable power this build-out needs. Southern Prairie is one example of the kind of project we develop in strategic locations."
Citations:
About Westbridge Renewable Energy S.A.
Westbridge Renewable Energy S.A. (WEB; OTCQX: WEGYF; FRA: PUQ) is a development-stage developer of utility-scale renewable energy infrastructure, including solar photovoltaic generation and battery energy storage systems, with a project portfolio across North America and Europe. The Company originates, develops and monetizes clean-power projects through their development lifecycle.
http://www.westbridge.energy  |  Twitter  |  LinkedIn
Third-Party Information
References to third parties and their projects or data — including Meta Platforms, Inc., Entergy, Google, Linea Energy, TotalEnergies, Enbridge, AES and demand and capacity estimates attributed to the International Energy Agency, Janus Henderson Investors, Goldman Sachs Research, McCarthy Tétrault LLP, Lexology, Osler Hoskin & Harcourt LLP and the U.S. Energy Information Administration — are drawn from publicly available information, are provided for illustrative market context only, and do not imply any relationship with, endorsement by, or commercial arrangement with those parties. As of the date of this news release, Westbridge has no relationship, agreement, arrangement or affiliation with Meta Platforms, Inc., and its Louisiana projects are independent of, and unrelated to, any Meta data-centre project.
Forward-Looking Statements
Certain information in this news release contains "forward-looking information" and "forward-looking statements" within the meaning of applicable Canadian securities laws, including, without limitation, statements regarding the completion of the Transaction and the satisfaction of its closing conditions and the timing thereof; the receipt and amount of the base purchase price and any contingent additional solar payment; the future development, permitting, construction and commercial operation of the Red Willow project; potential improvement in Alberta's renewable energy market and the impact of the Canada–Alberta TIER agreement and carbon-pricing framework; expected large-load, data-centre and AI-driven electricity demand and its potential effect on wholesale power prices; projected U.S. renewable capacity additions; potential future PPA demand; and the Company's development portfolio and its potential to support or benefit from these trends. Forward-looking statements are frequently identified by words such as "anticipate," "believe," "expect," "intend," "estimate," "potential," "positioned," "may," "could" and similar expressions.
Such statements are based on assumptions, including that the closing conditions to the Transaction will be satisfied; that announced agreements and regulations will be implemented as described; that forecast demand and capacity additions will materialize; and that the Company's projects will advance through permitting, interconnection, financing and construction on anticipated terms and timelines. Actual results may differ materially due to risks and uncertainties, including the failure to satisfy closing conditions or obtain required regulatory or stock exchange approvals; regulatory and policy changes; wholesale electricity price volatility; permitting, interconnection and construction risk; availability and cost of financing; and the other risk factors described in the Company's continuous disclosure filings available under its profile on SEDAR+ at http://www.sedarplus.ca. Statements regarding AI and data-centre demand describe market conditions and infrastructure the Company develops and should not be read to imply any signed hyperscaler or data-centre offtake, AI-related revenue, or contracted capability that has not been separately announced. There can be no assurance that the Transaction will be completed on the terms described, or at all, or that anticipated market developments will occur. The forward-looking statements in this news release are made as of the date hereof, and the Company undertakes no obligation to update them except as required by law.
Neither the TSX Venture Exchange nor its Regulation Services Provider (as that term is defined in the policies of the TSX Venture Exchange) accepts responsibility for the adequacy or accuracy of this release.
SOURCE Westbridge Renewable Energy S.A.
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Ulrich W. Paetzold is at the Institute of Microstructure Technology, Karlsruhe Institute of Technology, 76344 Eggenstein-Leopoldshafen, Germany, and at the Light Technology Institute, Karlsruhe Institute of Technology, Karlsruhe, Germany.
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Paul Fassl is at the Institute of Microstructure Technology, Karlsruhe Institute of Technology, 76344 Eggenstein-Leopoldshafen, Germany, and at the Light Technology Institute, Karlsruhe Institute of Technology, Karlsruhe, Germany.
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Market-leading solar cells use crystalline silicon to convert sunlight into electricity, but have essentially reached the limit of the percentage of incoming light that they can harness. Solar cells that use materials called perovskites in tandem with silicon can exceed the conversion efficiency of silicon-only devices and are rapidly approaching commercialization. Yet it remains uncertain which manufacturing process will enable economically viable production of such solar cells on an industrial scale¹. Writing in Nature, Luo et al.² report a key advance that suppresses the degradation of a compound that is used to make thin films of perovskites through a method called thermal evaporation. This enables the fabrication of high-performance perovskite–silicon tandem solar cells at much lower temperatures than have been needed previously, and at the sizes required for commercial production.
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By: Luis Reyes
Published: Aug 28, at 5:00am ET
America has decided to build its own solar supply chain, and it is not being quiet about it. Tesla filed paperwork this month for a $10.1 billion cell and module campus outside Houston. A presidential proclamation signed on August 6 drops a hard price floor under every imported panel starting December 4.
Europe ran this play first. The result is a building outside Catania, Sicily, roughly 2.15 million square feet of it (200,000 square meters), tooled to turn out 14,000 solar modules and 800,000 cells a day.
The equipment is all installed. The line is running. It has never run full.
That last sentence is the part worth carrying into any conversation about American solar factories. 3SUN, the Enel company that runs the plant, has the technology, about a billion euros of investment behind it and an Italian tax code that currently makes its modules the only realistic option for certain state incentives. None of that has filled the hall.
The site sits in the Etna Valley, the semiconductor cluster southwest of Catania, and it does both halves of the job under one roof: cells and modules. That vertical integration is the whole point, and it is rare in Europe.
The numbers come from Marina Foti, Head of Advanced Technology Development, R&D and Technology Transfer at 3SUN, who laid out the ramp at a technical conference covered by TaiyangNews in March. Roughly 200,000 square meters of floor. About 800,000 cells and 14,000 modules of daily capacity. A design target of 3 GW a year.
Total investment runs to about €1 billion, of which roughly €200 million came through European and Italian public programs. Enel’s own corporate page puts the 3 GW target at around 15,000 modules a day and lists 600 employees, on the way to a stated goal of 1,000 direct jobs.
Foti’s own account was the honest part. All the equipment has been commissioned, and the plant has not moved to full-capacity operation, because of where the market currently is. Enel was still advertising line-operator posts in Catania as recently as this spring.
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So the 3 GW figure is what the building can do on paper. It is not what came off the line last month, and anyone quoting it as output is quoting a blueprint.
Most of the world’s solar cells are TOPCon. 3SUN builds heterojunction, which sandwiches a crystalline silicon wafer between thin layers of amorphous silicon, and the manufacturing differences are not cosmetic.
HJT runs below 200°C. TOPCon processes can go past 800°C. HJT takes around six process steps where TOPCon takes roughly fourteen. Fewer steps and lower heat mean tighter process control and more automation, which is exactly what you want when your labor is European and your competitor’s is not.
The cells are symmetric, which lets you go thinner on the wafer and use less silicon. 3SUN’s cell efficiency sits above 24%, and its B60 module runs 610 to 640 watts with bifaciality up to 90%. A bigger B66 with 132 cells and up to 730 watts has been slated for this year.
The catch is silver. HJT has always eaten more of it than TOPCon, along with indium in the transparent conductive layer, and silver is not getting cheaper. The industry response is copper: at a TaiyangNews equipment conference on August 25, DKEM’s Cong Chen put silver-coated copper paste for HJT at 3.4 mg per watt. 3SUN is working the same problem from silver-copper pastes toward straight copper metallization and indium-free coatings.
Good technology, then. Which has never been the thing that kills a European solar factory.
Meyer Burger was the European HJT champion, the company whose SmartWire designs got licensed around the industry. It opened a 1.5 GW module plant in Goodyear, Arizona in 2024, the only HJT manufacturer in the United States.
Then D. E. Shaw Renewable Investments terminated a supply agreement covering up to 5 GW in November 2024, and the whole thing came apart fast. The German subsidiaries filed for insolvency on May 31, 2025. Arizona production stopped the same day and the US workforce was let go. Chapter 11 followed on June 25, 2025, and the assets were sold off inside 90 days.
American appetite for the technology did not die with it. TOYO and SEG Solar have both pushed HJT cell and module plants forward in the US this year. But the cautionary tale is sitting right there: the technical case for HJT was never the problem, and it did not save anybody.
Here is where Catania stops looking like a factory story and starts looking like a policy one.
A 2023 Italian decree set up a register at ENEA sorting EU-made modules into three categories. Category A covers EU-made modules at 21.5% module efficiency or better. Category B needs EU cells and modules at 23.5% cell efficiency. Category C requires bifacial silicon heterojunction or tandem cells made in the EU, at 24% cell efficiency or better.
An amendment in December 2025 knocked category A out of Italy’s 2026 super-depreciation benefit, leaving only B and C. Category B currently has no modules registered at all. Category C is nearly empty of anything actually in production, because Meyer Burger is still listed and no longer manufacturing.
Which leaves, in practice, one supplier. Eleven European manufacturers filed a complaint with EU institutions objecting to what they called a possible de facto monopoly, according to Italian energy outlet QualEnergia, which has tracked the rule since it appeared.
No EU body has ruled on that complaint, and no authority has found 3SUN or Enel in violation of anything. The rules were written by the Italian legislature, not by the company that benefits from them. But it is worth sitting with the arithmetic: a factory with a legally protected home market still has not filled its building.
The reason anyone outside Italy pays attention to Catania is perovskite. 3SUN stacks a perovskite top cell on an HJT bottom cell in a two-terminal design, developed jointly with France’s CEA at the INES campus.
The lab results are real. CEA and 3SUN certified 30.8% efficiency in January 2025 on a 9 cm² cell, up from 28.4% a year earlier. Most tandem records get set on 1 cm², so the larger area matters for anyone who wants to eventually build these by the million.
The timeline is the part that has moved. Enel Green Power was once talking about offering tandem modules from 2026. The current target, per Foti’s March presentation, is initial industrial deployment before the end of the decade, with the technology moving from lab cells onto a pilot line running full wafer formats.
The wider industry roadmap agrees with the slower version. Presenting the latest ITRPV findings at that same August conference, Markus Fischer projected tandem reaching about a 15% share of the market by 2036, at mass-production module efficiencies around 31%. HJT and TOPCon are still doing the work in the meantime.
So Catania is not shipping tandem panels. It is running heterojunction on the main line and perovskite on a pilot next door, and telling you honestly which is which.
Tesla’s filing with the Texas Comptroller, signed July 22 and surfacing publicly on August 6, asks for a ten-year property tax limitation on a 3,050-acre site near Richmond. The capital number is $10.116 billion, split into about $1.5 billion of real property and $8.6 billion of equipment, with 9,712 permanent jobs projected and commercial production targeted for the first quarter of 2029.
The application does not state a nameplate capacity. Joe Hennessy, market research analyst at PV Tech Research, called it as big as anything the sector has seen for a single site, and estimated it could clear 10 GW. Tesla says it is still weighing a competing out-of-state location.
The gap this is meant to close is real. US module assembly capacity was running around 60 GW in early 2026 while domestic cell capacity sat under 15 GW, which is why the December 4 proclamation sets separate floors at $0.22 a watt for cells and $0.38 for modules, plus a 15% tariff on the derivative products.
Catania is what the far end of that road looks like when the building goes up before the demand does. Sicily has the vertical integration Texas is proposing, the technology Arizona lost, roughly €1 billion spent, and a national tax code that currently steers buyers toward its modules and almost nobody else’s.
It still has not filled the hall. The building was never the hard part.
Did we nail it or blow it?
Luis Reyes · Aug 24, 2026
Luis Reyes · Aug 19, 2026
Dave McQuilling · Aug 13, 2026
Luis Reyes · Aug 12, 2026
Luis Reyes · Aug 14, 2026
Luis Reyes · Aug 10, 2026
Olivia Richman · Aug 27, 2026
Chema Bonilla Díaz · Aug 27, 2026
Luis Reyes · Aug 27, 2026
Luis Reyes · Aug 27, 2026
Luis Reyes · Aug 27, 2026
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Solar project, meant to power 70,000 homes near KCI, put on hold indefinitely  Kansas City Star
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Utilities can avoid some costly emergency measures, while customers can earn money from equipment they already have.
Photo Credit: Reddit
A new in-app offer gave a home battery owner in Louisiana a look at a growing energy trend in which utilities pay residents to share stored power when the grid is under strain.
A FranklinWH customer wrote on Reddit that they were shown a new in-app promotion offering cash rewards tied to a utility’s use of their battery during high-demand periods.
“If I tap through the link, it brings me to an enrollment page, which touts how much money I could theoretically earn, but without much information about what I need to do or how the program works,” they said.
Trying to get a clearer picture only raised more questions. The signup page focused on how much money participants might make, while giving little detail about what enrollment would actually involve. They added that the terms and conditions were only slightly more helpful and that a linked Greater Grid page for Entergy Louisiana led to a 404 error.
Programs like the one described in the post are often part of a virtual power plant model, in which large numbers of home batteries are coordinated to ease grid strain during times of high demand. When these programs work well, utilities can avoid some costly emergency measures, while customers can earn money from equipment they already have installed.
Battery storage is one of the most effective ways to protect a home during outages, particularly when storms or grid disruptions interrupt service. It can also help households lower energy costs by storing power for later use and, in some cases, support a more off-grid lifestyle.
The battery itself is only one part of the equation. Program rules, compensation structures, export permissions, and utility billing treatment can all shape whether an offer that looks appealing on paper is actually worth it.
For anyone comparing home storage options, the math depends on several factors, including the manufacturer, the upfront installation price, and how much energy the system can hold. A battery that already proves useful during outages may look even better if it also brings in ongoing utility-program payments.
FROM OUR PARTNER
Want to go solar but not sure who to trust? EnergySage has your back with free and transparent quotes from fully vetted providers in your area.
To get started, just answer a few questions about your home — no phone number required. Within a day or two, EnergySage will email you the best options for your needs, and their expert advisers can help you compare quotes and pick a winner.
Solar panels can save you more than $50k over their 25-year lifespan, and EnergySage can help you save as much as $10k on installation. Which begs the question — isn’t that worth an email or two?
Full terms in plain language can clarify how often the battery may be called upon, whether a minimum reserve level will be maintained for backup protection, and how any credits will appear on the utility bill.
Manufacturers, utilities, and program operators can help by making enrollment pages easier to understand and ensuring support links stay active. Clear examples of expected earnings, battery usage, and customer protections could go a long way toward building trust.
For homeowners still weighing whether battery storage is worth the investment, EnergySage is a great resource to compare prices and access incentives. Those who want backup power but are not ready for a whole-home system can also look into alternatives such as Pila.
Get TCD’s free newsletters for easy tips, smart advice, and a chance to earn $5,000 toward home upgrades. To see more stories like this one, change your Google preferences here.
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Waaree Renewable Technologies Secures LOA for 291 MWp Solar PV and 280 MWh BESS Project  SolarQuarter
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California legislators approved a bill on Aug. 26 that could help reduce skyrocketing energy costs for residents by allowing them to install plug-in solar panels as an alternative, portable way to meet household energy needs.
The bill, Senate Bill 868, authored by Senator Scott Wiener (D-San Francisco), would establish safety standards for portable solar systems, also known as “balcony solar systems,” which allow residents who may not be able to install a rooftop solar system to still take advantage of California’s sunny climate.
With this system, residents can place a few small solar panels in their backyard or on their balcony to generate energy, then plug the system directly into their home’s standard 120‑volt outlet to prioritize drawing from the solar panels rather than the electrical grid.
“This is a way that we can expand access to solar to a huge array of Californians who are not benefiting now, including renters, including people who own smaller, more modest homes,” Wiener said when he introduced the bill to the California Senate Committee on Energy, Utilities and Communications, on March 17.
The bill is now heading to Gov. Gavin Newsom’s desk, awaiting either his signature or a veto.
Although these portable solar systems are new to California, this emerging technology is being widely adopted in Europe; in Germany, over 1 million systems have been installed nationwide, according to the World Resources Institute.
This wide adoption is evident as it’s become available at stores like IKEA, which offer affordable plug-in solar systems on their European websites, starting at about $570 as of August 2026.
Additionally, eight other states have already taken a leap of faith by approving plug-in solar legislation, with Utah becoming the first state to legalize the practice in 2025.
When it comes to energy costs, Californians experience some of the highest rates in the nation, stemming from state subsidies, infrastructure investments and companies increasing their rates over the last few years,
When Wiener introduced the bill, he noted that residents have been fighting the affordability crisis as rates continue to rise year over year. He specifically pointed attention to customers of companies like Pacific Gas and Electric Co., which have seen their electricity rates increase by “nearly 40% between 2022 and 2025.”
Advocates for plug-in solar systems, such as Solar United Neighbors, argue that adopting this technology could help California residents save $400 to $800 annually.
“A typical plug-in system can cut your electricity bills by several hundred dollars per year. The average payback time for a system purchased today is about five years,” the Solar United Neighbors website reads. “The cost for plug-in solar is forecast to drop from nearly $3/watt today to just under 60¢/watt within 2-3 years of enabling legislation in a critical mass of states.”
Although the bill passed both the California Assembly and the Senate, organizations such as the California State Association of Electrical Workers expressed their disapproval of the new law and the technology as it made its way through the chambers.
The association was primarily concerned about the potential danger of allowing consumers to purchase and install plug-in solar systems without establishing installation, maintenance or inspection standards.
“This is a dangerous precedent, because adding additional current from a (Plug-In Photovoltaic) system that is not protected by an upstream panelboard branch circuit overcurrent protective device – rather than hard-wiring into a home’s main electrical panel – could overload conductors, increasing the risk of electric shock and fire,” the CSAEW statement reads.
“It is a near certainty that, if PIPV solar generation is approved, an unsuspecting homeowner or renter will unknowingly create a hazardous situation, putting their home and/or loved ones at risk.”
Although the bill does not require residents to hire a professional or seek approval from an “electric corporation or a local publicly owned electric utility” to install these plug-in systems, it does allow a company to require customers to notify and register their devices with the company.
Additionally, companies will not be allowed to pay any fees related to the device or to force residents to connect their devices to a building’s electrical system.
Noe Padilla is a Northern California Reporter for USA Today. Contact him at npadilla@usatodayco.com, follow him on X @1NoePadilla or on Bluesky @noepadilla.bsky.social. Sign up for the TODAY Californian newsletter or follow us on Facebook at TODAY Californian.

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Hongqi has developed a prototype solar sunroof using perovskite photovoltaic technology.
Chinese automaker FAW Hongqi has unveiled a prototype solar sunroof that uses next-generation perovskite photovoltaic technology to turn part of an electric vehicle into a power generator.
The full-size prototype, installed on Hongqi’s EHS7 electric SUV, can reportedly produce up to 300 watts of power under sufficient sunlight and generate around 400 kilowatt-hours of electricity annually.
While solar roofs are not new, Hongqi’s approach replaces conventional crystalline silicon cells with thin and flexible perovskite photovoltaic materials. The company ultimately hopes to expand the technology beyond the sunroof and onto other parts of the vehicle, potentially allowing an EV to generate enough electricity for up to 80 km (50 miles) of driving range per day.
According to reports, Hongqi integrated the perovskite photovoltaic elements directly into the panoramic sunroof of the EHS7, which is sold in China as the Tiangong 08.
Unlike conventional crystalline silicon solar cells, perovskite-based photovoltaics can be thinner, lighter, and more flexible. Those characteristics could make them better suited to the curved surfaces and complex shapes found on modern vehicles. However, integrating the material into a car roof presents its own engineering challenges.
Hongqi’s researchers reportedly had to address the sensitivity of perovskite materials to water, oxygen, and ultraviolet radiation, while also adapting the photovoltaic layer to the curved glass surface of the panoramic roof. The prototype reportedly generates up to 300 W in sufficient sunlight, with annual energy production estimated at approximately 400 kWh.
That electricity would not necessarily be used solely to charge the vehicle’s main traction battery. Instead, Hongqi said the solar roof could help supply lower-voltage electrical loads, including air conditioning, refrigerators and the vehicle’s sentry or monitoring systems.
The bigger ambition lies beyond the roof. Hongqi plans to explore integrating perovskite photovoltaic elements into additional body panels, including the hood. If enough surface area can be covered with solar cells, the company estimates that a vehicle could generate as much as 10 kWh of electricity per day.
According to Hongqi, that could theoretically translate into up to 80 km (50 miles) of additional driving range under favorable conditions. The actual energy produced would depend on factors such as sunlight intensity, weather, parking location, and the total photovoltaic surface area available. Hongqi has also not provided a timeline for bringing the technology into production vehicles.
Still, the prototype highlights why automakers are increasingly interested in perovskite solar technology. Traditional silicon panels can be difficult to integrate into vehicle surfaces because of their rigidity and weight. Perovskites, meanwhile, offer the possibility of lightweight and potentially flexible solar layers that could conform to roofs, hoods and other body panels.
The solar sunroof is part of a broader technology push from Hongqi as the historic Chinese luxury brand expands its electric vehicle lineup. The EHS7 used for the prototype is a large electric SUV with a reported WLTP range of up to 475 km and peak power of 253 kW.
Hongqi is also exploring other advanced EV technologies, including high-power charging systems and solid-state battery development. The solar sunroof remains a prototype. But if the company can overcome the durability and manufacturing challenges associated with perovskite photovoltaics, future EVs may do more than simply consume electricity. They could generate a small but potentially useful portion of it themselves.
Kaif Shaikh is a journalist and writer passionate about turning complex information into clear, impactful stories. His writing covers technology, sustainability, geopolitics, and occasionally fiction. A graduate in Journalism and Mass Communication, his work has appeared in the Times of India and beyond. After a near-fatal experience, Kaif began seeing both stories and silences differently. Outside work, he juggles far too many projects and passions, but always makes time to read, reflect, and hold onto the thread of wonder.
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JinkoSolar Reports RMB 12.36 Billion Q2 2026 Revenue as Module Shipments Rise 16.7% Sequentially  SolarQuarter
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Renting remains expensive, but buying a home is even farther out of reach for many Americans.
Photo Credit: iStock
The average rent in Phoenix still sits below the U.S. average, yet that relative advantage can be diminished by heavy summer air conditioning expenses.
A new rental snapshot shows that even a relatively small increase in rent can still push the income needed to stay financially comfortable much higher for many households.
According to Zillow’s July rental data summarized by AZFamily, Phoenix’s average rent was $1,727 in July. That was 0.3% higher than in July 2025, although still below the national July average of $1,962.
A typical Phoenix-area renter would need about $69,094 in annual income to afford a standard rental.
Want to go solar but not sure who to trust? EnergySage has your back with free and transparent quotes from fully vetted providers in your area.
To get started, just answer a few questions about your home — no phone number required. Within a day or two, EnergySage will email you the best options for your needs, and their expert advisers can help you compare quotes and pick a winner.
Nationwide, the income needed for a typical rental was roughly $78,488 a year, and Zillow said rent growth reached 2.3% — the fastest pace in more than a year.
For homeowners who are feeling squeezed by bills, going solar is one of the best ways to save money on home energy. It may be worth exploring EnergySage to get free solar installation estimates and compare quotes.
Renting remains expensive, but buying a home is even farther out of reach for many Americans.
Zillow estimated that affording a typical mortgage in the U.S. requires nearly $99,800 in yearly income, which is more than $21,000 above the amount needed for a typical rental — a gap that could keep more people in the rental market longer, adding pressure even in cities where rents are not rising as quickly as the national average.
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To get started, just answer a few questions about your home — no phone number required. Within a day or two, EnergySage will email you the best local options for your needs, and their expert advisers can help you compare quotes and pick a winner.
And in Phoenix, monthly housing costs extend beyond the lease payment, since summer air conditioning use can sharply increase household monthly spending.
On paper, Phoenix fares somewhat better than the country as a whole, but that does not necessarily translate into noticeable relief for local renters.
For renters, revisit monthly budgets, check whether there is room to negotiate at lease renewal, and compare neighborhoods or unit sizes before signing a new lease. Even small savings on utilities can make a difference when housing already takes up a large share of income.
For homeowners looking to cut another major recurring expense, EnergySage’s free services can be a useful tool. With EnergySage’s help, the average person can save up to $10,000 on solar purchases and installations. EnergySage’s solar map shows the average cost of a home solar panel system on a state-by-state level, along with solar panel incentives available in each state. Together, these resources can help readers get the best price for rooftop solar panels and access available incentives.
💡Go deep on the latest news and trends shaping the residential solar landscape
Adding battery storage to a solar setup is also one of the best ways to protect your home during outages, save money on energy, and go off-grid. For households worried about both rising bills and power disruptions, that extra backup can add resilience as well as long-term savings. Readers can also explore EnergySage for information about home battery storage options, including competitive installation estimates.
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CrossBoundary Energy’s solar photovoltaic and battery energy storage system serving the Kamoa-Kakula copper complex in the Democratic Republic of Congo has reached commercial operation and is now supplying 30 MW of firm baseload power to Kamoa Copper. The facility entered commercial operation on August 12, 2026, around 16 months after the power purchase agreement was signed in April 2025. The system combines 233 MWp of solar PV capacity with 123 MVA/526 MWh of battery storage and is designed to provide continuous power at a 95% annual availability factor.
During early operations, the solar plant has already delivered more than 150 MW of output, with around 50 MW supplied directly to the mine network and the balance used to charge the battery system, according to CrossBoundary figures cited by Energy-Storage.news. The facility’s maximum expected solar output is around 180 MW, while the battery system enables renewable generation to be stored and dispatched outside daylight hours, supporting the 30 MW round-the-clock power guarantee.
The new facility adds another source of reliable electricity to Kamoa-Kakula, which is principally owned by Ivanhoe Mines, Zijin Mining and the DRC government. The operation already relies on hydropower supplied through cooperation with state utility SNEL, while solar-plus-storage is intended to reduce reliance on diesel generation and strengthen the resilience of the mine’s power supply.
The start of commercial operation represents an important infrastructure milestone for Kamoa-Kakula, where power reliability remains critical to stable mining and processing. Although the 30 MW firm-power contribution is modest relative to the complex’s overall electricity requirements, the combination of large-scale solar generation and battery storage provides an additional layer of supply security and could reduce exposure to diesel costs and grid-related disruptions.
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Energy News Beat
The Intersection Between Energy and Finance
Commercial production is targeted for the first quarter of 2029 if Tesla picks the Texas site, wins incentives, and clears permits. Tesla has not disclosed annual gigawatt output, so any panel-count figure is an estimate, not an official number.
The internal name is Project Crystal Sun. The public paper trail is a Jobs, Energy, Technology and Innovation (JETI) application, file J0050, with Lamar Consolidated ISD and the Texas Comptroller of Public Accounts. It was signed July 22, 2026, posted August 6, and later supplemented on August 14 and August 20.
Tesla has not issued a standalone press release announcing the plant. A company spokesperson did not comment when asked. The closest official Tesla language is in the Q2 2026 shareholder update and Form 10-Q: site work and equipment procurement for solar manufacturing “progressed,” and the company is “developing our solar manufacturing.” CFO Vaibhav Taneja said on the earnings call that Tesla intends to multiply U.S. solar manufacturing “by an order of magnitude.”
The application describes a solar-cell manufacturing campus on portions of five parcels totaling about 3,050 acres near Richmond / Needville, along FM 762 and FM 1994 in Fort Bend County, southwest of Houston.
Planned investment: $10.116 billionAbout $1.5 billion real property
About $8.6 billion equipment and personal property
Spend is front-loaded in three years:2026: about $2.33 billion
2027: about $3.29 billion
2028: about $4.49 billion
Then commercial operations in Q1 2029. The requested JETI limitation would run 2029–2038.
The equipment list is the important part. Tesla is not describing a simple module-assembly line like Buffalo. The filing lists ingot manufacturing, wafer manufacturing, coating, metallization and printing, cell testing, cleanrooms, and automated material handling — an ingot-to-cell (and potentially module) stack. The NAICS code is 334413, semiconductor and related device manufacturing.
Kroll’s economic statement attached to the filing projects 9,712 permanent jobs at full buildout, a peak of about 1,147 construction jobs, roughly $107 billion in Texas GDP impact, and about $6.4 billion in state and local tax revenue over 38 years. Those are consultant projections used to support a tax deal, not audited results.
The filing is real. The factory is not locked.
Tesla’s own application says it is evaluating sites “across multiple U.S. states,” comparing Fort Bend with an unnamed out-of-state alternative, and that without the JETI limitation plus local abatements the Texas site’s economics are worse. If incentives fail, Tesla says it would further evaluate the investment outside Texas.
That is how large Texas incentive filings work: they put a maximum project on paper so the company can shop tax treatment. SpaceX used the same JETI process for its Texas chip plans. Crystal Sun should be treated as a site-selection and incentive bid, backed by real spending signals, not as a notice to proceed.
Those spending signals matter. Tesla’s Q2 2026 materials already listed solar manufacturing among multi-year infrastructure buildouts. Earlier in 2026, reporting pointed to large purchases of solar manufacturing equipment (including from Chinese toolmakers such as Suzhou Maxwell) and to a possible Houston-area solar build near Tesla’s Megapack Megafactory in Brookshire. Crystal Sun is a different Fort Bend greenfield, about 45 minutes southwest of Houston. It may replace, complement, or compete with that earlier site rumor. Tesla has not publicly reconciled the two.
Elon Musk’s January 2026 World Economic Forum remark is the strategic frame Tesla cited in the filing: SpaceX and Tesla teams are separately working toward 100 GW a year of manufactured solar power in the United States, “that’ll probably take us three years or something.” A Tesla solar-manufacturing job posting earlier in 2026 used similar language: a 100 GW facility from raw materials in the United States before the end of 2028. Crystal Sun is the first large public capital number attached to that goal. It is not proof the 100 GW target will be hit on that timetable.
On Tesla’s own calendar:
“This year” construction is possible only if Texas wins the site fight and local approvals move fast. As of late August 2026, the Comptroller page still shows the application in the posted / supplement phase, not an executed JETI agreement. After completeness review, the Comptroller has a statutory window to recommend the project to the Governor; the school district and Governor must then agree. Fort Bend County would still need to create the reinvestment zone.
A 2029 start is aggressive for a greenfield, vertically integrated cell fab, but it is consistent with buying turnkey Asian production tools and running Tesla as its own general contractor — something Taneja noted Tesla already does on most of its factories. It is not consistent with Musk’s “about three years” 100 GW comment if that clock started at Davos in January 2026. A plant that first ships in early 2029 cannot be at 100 GW in 2028. Investors should treat 100 GW by 2028 as an aspiration across Tesla’s whole solar program (Buffalo plus new sites), not as Crystal Sun’s opening rate.
Tesla did not disclose nameplate capacity. That is the most important capacity fact in the filing.
What is known:
Buffalo / Gigafactory New York currently assembles Tesla’s new TSP-420 residential panels at on the order of 300 MW per year — Tesla’s first in-house-designed conventional module, shipped starting Q1 2026. Crystal Sun would be a different order of magnitude if built as described.
Musk’s public target is 100 GW/year of U.S. manufactured solar for Tesla (and separately for SpaceX).
One industry read of the $10.1 billion capex is that this campus is a foundation stone toward that target, not the entire 100 GW by itself. Another estimate circulating in trade coverage suggested on the order of $16 billion might be needed to reach 100 GW of fully integrated U.S. capacity. Neither figure is Tesla guidance.
A simple illustration, not a forecast: 100 GW is 100 billion watts. At Tesla’s current 420 W residential module, that would be roughly 238 million panels a year. Utility modules in the 600–700 W class would mean fewer physical panels for the same watts. Crystal Sun’s actual annual output could be a slice of that, all of it, or something else entirely. Until Tesla names a GW rating, panel-count headlines are speculation.
Homeowners and edge-grid resilience, or solar farms and Megapacks?Both, according to the filing. Storage pairing is Tesla’s business model, not a stated exclusive offtake contract for this plant.
The application says the plant would make photovoltaic cells and/or assembled modules “for deployment in utility-scale, commercial, and distributed solar installations,” and discusses utility-scale plus on-site, behind-the-meter generation. That is the full market stack: rooftops, C&I, and solar farms.
Tesla’s current consumer product is already a resilience package. Official Tesla materials describe 420 W panels engineered in California, assembled in Buffalo, with 18 “power zones” for shade performance, a rail-less Panel Mount, and integration with Powerwall and the Tesla app. Tesla discontinued Solar Roof tiles in August 2026 and pointed customers to conventional panels. Energy revenue growth has been storage-led — Powerwall and Megapack — not rooftop generation. Megafactory Texas is scheduled to start Megapack production in 2026, which would sit in the same broader Houston-area energy cluster if Crystal Sun is built.
The strategic logic is obvious: domestic cells reduce tariff and supply-chain risk; Tesla can feed Buffalo residential assembly, third-party installers, its own storage-plus-solar packages, and utility projects that sit in front of Megapacks. Musk has also tied large-scale solar to AI electricity demand and, separately through SpaceX, to space-based power. The Fort Bend filing does not assign output to orbital arrays. SpaceX has its own solar-manufacturing track.
For Energy News Beat readers, the clean read is this: Crystal Sun is designed as a cell and module foundry, not a residential-only factory and not a captive solar-farm EPC shop. If Tesla executes, homeowners get a more secure domestic panel supply paired with Powerwall. Utilities and data-center offtakers get a potential U.S. cell source that can be coupled with Megapack. The mix will be set by price, 45X production credits, and which customer can absorb volume first.
Crystal Sun is the largest U.S. manufacturing investment Tesla has put on a Texas incentive form. It is also still a maybe. The factory becomes “real” when Tesla stops evaluating other states and starts pouring slabs.
Appendix: sources and links
Official/primary
Filing and project reporting
Musk 100 GW remarks and Tesla Energy context

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Silver’s Solar Demand Boom Starts to Fade as High Prices Bite  Bloomberg.com
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