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Qualitas Energy, a leading global investment and management platform with a dual focus on both funding and developing renewable energy, energy transition, and sustainable infrastructure, has announced the acquisition of a development-stage solar photovoltaic (PV) project in the United States, with a planned capacity of 164 MWp.

Qualitas Energy acquires 164 MWp solar PV project in the United States

The asset, located in Illinois within the Midcontinent Independent System Operator (MISO) market, has been acquired from Bechtel Enterprises. Notice to Proceed (NTP) is expected in the second quarter of 2028, with Commercial Operation Date (COD) targeted for the third quarter of 2029. The project has 100% site control, is fully permitted and benefits from strong local community support, having received unanimous approval as part of the county permitting process.
Qualitas Energy will leverage its integrated investment, development and asset management capabilities to further de-risk the asset and advance it into its next phases, including the optimisation of offtake strategy, procurement, construction planning and financing. The project also offers additional value creation potential through the future integration of up to 64 MWac of battery energy storage capacity, which could support the structuring of a bundled solar-plus-storage power purchase agreement (PPA), enhancing its commercial flexibility and long-term revenue profile.
In addition, the asset benefits from a favourable interconnection position within the MISO market and offers strong commercial optionality, with access to both the Minnesota and Illinois hubs. This provides a broad range of potential offtake routes, including corporate and industrial customers, hyperscalers, traditional utilities and public renewable energy procurement programmes.
This transaction was undertaken through Qualitas Energy Fund VI, the firm’s latest flagship vehicle, launched at the end of 2025.
'This acquisition reflects Qualitas Energy’s disciplined investment approach and its ability to identify high-quality renewable energy assets with strong value creation potential. The project combines advanced development status, strong fundamentals and multiple commercialisation pathways in one of the country’s most attractive power markets. This transaction also underscores the strategic relevance of the United States for Qualitas Energy,' said Alejandro Ciruelos, Partner – US at Qualitas Energy.
Qualitas Energy was advised by Norton Rose Fulbright (legal), Sargent & Lundy (technical), and Leo Berwick (financial and tax).
Original announcement link
Source: Qualitas Energy

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UNSW Scientia Professor Martin Green was this week recognised as Honorary Chair for Life in acknowledgement of his pioneering contributions to global solar technology innovation at the annual SNEC PV Power Expo and Conference in Shanghai, China. Here, he also presented the latest advancements and future direction of silicon solar cell technologies, including improving the stability of perovskite solar cells for large-scale application.​
Credit: UNSW Sydney
Out on a patch of land near Sydney’s northern beaches, a new generation of solar panels are sitting out in the salt air, heat, humidity and rain. They are facing the harsh tests of nature and time. And if they fail, that could be quite useful.
For UNSW Sydney’s Scientia Professor Martin Green – who is often described as the father of modern photovoltaics – the future of solar power now depends not on an efficiency world record but on whether the next generation of solar cells can survive outside the lab.
Prof. Green has spent more than five decades helping solar power become a cheap source of electricity, with the technology he developed today underpinning 90% of the world's solar technology.
Now, he is helping establish an independent field-testing facility at UNSW’s Water Research Laboratory in Manly Vale, where the newest solar tech – perovskite solar modules – will be subjected to durability testing under real-world conditions.
Green says while these modules are already on the market, the expectation is that failed modules can simply be replaced as production scales and costs continue to fall.
“Silicon modules are routinely sold with warranties of 25 to 40 years,” Prof. Green says.
“While the perovskite modules offer similar warranties, the likelihood of a module surviving for that long is very small.”
Perovskites are a class of crystalline materials that can be stacked on top of silicon solar cells to harvest more sunlight and push solar performance further – the next generation of solar technology.
The new technology performs impressively in lab but is yet to survive for decades in the real world.
In the latest international solar cell efficiency tables – published last week in Joule –  Prof. Green records a large-area silicon cell reaching 28.1% efficiency and a tiny perovskite cell – not a full-size commercial module – reaching 28.0%. This is the first time the best single-junction perovskite result has effectively matched the highest silicon result.
The same report includes a 35.2% efficiency result for a perovskite-on-silicon tandem cell.
In a solar cell, a few percentage points make a massive difference. Higher efficiency means more electricity from the same rooftop, less land required for solar farms, with lower installation and infrastructure costs across entire energy systems.
The report’s latest numbers suggest solar is edging towards another technological shift – if the cells can last.
“Silicon, the workhorse of the global solar revolution, is now very efficient, but increasingly close to its limits,” Prof. Green says.
“And anyone who’s made a perovskite cell knows how unstable they are.”
Testing the future
Can perovskites make the same leap silicon did from promising technology to reliable infrastructure?
This question is what shapes the field-testing facility.
Prof. Green says perovskite-on-silicon tandem cells are the most likely large-scale commercial pathway for next-gen solar technology.
“All the silicon manufacturers have their own perovskite-on-silicon programs,” he says.
When his group first began setting records with silicon cells, he insisted any claims be certified by recognised testing laboratories.
“If you’re claiming a record, you’ve got to have it independently certified,” he says.
That insistence on verification became a foundation of the modern solar industry. And it persists today through the independent field-testing facility Prof. Green is helping establish alongside his former student, UNSW’s Dr Jessica Jiang.
The facility will be able to install up to 160 modules, catering to all manufacturers and generations of products.
Many perovskite manufacturers are part of China’s rapidly expanding solar industry – and Prof. Green’s former students.
One of the largest perovskite manufacturers, Microquanta, was started by two former students.
Another former student is the founder of Suntech, Dr Zhengrong Shi, whose commercialisation of modern solar technology helped catalyse China’s rise as a global solar manufacturing powerhouse.
“Jessica has really good contacts within the Chinese industry, largely because they’re former students who now have important jobs in the industry,” Prof. Green says.
“She can WeChat them and the next day they’ll put a module in the mail.”
By comparing modules from different companies, the UNSW team hopes to identify which failure mechanisms are widespread and which are specific to individual designs.
“We’ll be able to provide an authoritative opinion about just how good the commercial ones are,” Prof. Green says.
“Once they fail in the field, we’ll find out why and provide that information back to the manufacturer,” he says.
“We really think we can push things along a bit.”
From oil shocks to world records
When Prof. Green began working on solar cells in the early 1970s, photovoltaics were niche and expensive.
The cost didn’t matter so much in the space industry, which had been using solar cells in spacecraft since the late 1950s. But back down on Earth, they were too expensive to be taken seriously as an everyday power source.
Then, the oil crises of that decade forced governments to think seriously about energy security – particularly after embargoes disrupted fuel supplies across the Western world.
“There were queues at service stations, cars running out of petrol – in a world suddenly worried about oil dependence,” Prof. Green says.
He says solar then “got a guernsey” in efforts to reduce dependence on imported oil.
“They had to bring the cost down by a factor of a thousand or more from what they cost to put on satellites,” he says.
At the time, nuclear power dominated much of the energy imagination. Prof. Green says one nuclear advocate dismissed solar as likely to have “all the impact of a flea on an elephant’s back”.
But, he says, the political and scientific mood began to shift. A US program helped set the international tone. Japan launched its Sunshine Project. Europe followed with its own efforts. And Australia began its own solar program in 1978.
Prof. Green joined UNSW as an academic in 1974 and set up a solar research group soon after. By the early 1980s, his group was known internationally.
In 1983, he and his team invented Passivated Emitter and Rear Cell (PERC) technology. This led to them then producing the world’s first officially confirmed 18% efficient silicon solar cell, beating the previous record of 16.5%.
That result pushed UNSW to the front of a field that included major US companies, NASA-linked programs, Japanese laboratories and other universities – with Prof. Green’s research team holding the record for silicon solar cell efficiency for much of the past four decades.
And last year, solar generated more electricity worldwide than nuclear for the first time, with the gap rapidly increasing.
Faster than expected
The role of solar today has expanded to being a resource that combats climate change. But its appeal still sits with its 1970s roots – as a technology tied to energy security, economic resilience and independence from volatile fossil fuel markets.
In Australia, solar already supplies a substantial share of electricity. Prof. Green says the contribution from solar is now doubling every few years and could become the dominant source of electricity far sooner than many expect.
“We’ll be generating most of our electricity from solar by about 2032,” he says.
He says conservative energy forecasts have repeatedly underestimated renewable deployment. Even projections that now speak positively about renewables, he says, often still assume they will play a smaller role than growth trends suggest.
For someone who has spent more than five decades not just watching, but helping solar outperform expectations, he is reluctant to underestimate what comes next.
“Things have exceeded even my projections as an optimistic person in the field.”
Disclaimer: AAAS and EurekAlert! are not responsible for the accuracy of news releases posted to EurekAlert! by contributing institutions or for the use of any information through the EurekAlert system.
Media Contact
Melissa Lyne
University of New South Wales
m.lyne@unsw.edu.au

University of New South Wales


Copyright © 2026 by the American Association for the Advancement of Science (AAAS)
Copyright © 2026 by the American Association for the Advancement of Science (AAAS)

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From pv magazine India
Solarium Green Energy, a rooftop solar engineering, procurement, and construction (EPC) company in India, has commissioned a fully automated solar module manufacturing facility with an annual production capacity of 1 GW in Ahmedabad, Gujarat.
The facility, equipped with advanced manufacturing machinery, was set up with capital expenditure of around INR 900 million ($9.6 million), excluding working capital.
“The plant is capable of manufacturing large-format G12 solar modules of up to 725 Wp. It will produce high-efficiency crystalline silicon solar PV modules using technologies such as TOPCon cells, half-cut cells, and bifacial modules, supported by high-precision imported equipment including tabber-stringers, laminators, and sun simulators,’ said the company.
Solar modules account for 50% to 60% of total EPC project costs. With the commissioning of this facility, Solarium expects to strengthen its supply chain, reduce dependence on third-party suppliers, accelerate execution timelines, and improve margins through captive consumption. This move also positions Solarium as an integrated solar solutions provider.
Solarium said that at approximately 85% plant utilization, the facility has the potential to generate annual revenues exceeding INR 10 billion, subject to prevailing market conditions and module pricing, if modules are sold externally. The facility is expected to serve both internal requirements and external customers, including other EPC players and the broader business-to-business (B2B) market.
“The commissioning of this facility marks a significant milestone in our growth journey. Delivered in under nine months, the plant reflects our strong execution capabilities,” said Ankit Garg, chairman and managing director of Solarium Green Energy Ltd. “With a fully automated line capable of producing high-efficiency G12 modules of up to ~725 Wp, this facility strengthens our supply chain, enhances execution capabilities, and supports margin improvement across our EPC business.”
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The Ministry of New and Renewable Energy has directed all ALMM-listed solar cell and module manufacturers to report monthly price ranges of domestically manufactured products to the National Institute of Solar Energy, aiming to enhance market transparency and prevent profiteering amid the implementation of ALMM List-II from June 1, 2026.
June 04, 2026. By Mrinmoy Dey

Future of Renewable Infra Will Be Built on Resilient Structures, Not Cheapest Ones: Vedant Goel

AI, Digitalisation Will Drive Next Phase of India’s Energy Transition: Schneider’s Udai Singh

Iron-Air Batteries Can Power India’s Renewable Ambitions: Stuti Kakkar, Meine Electric

India’s EV Future Depends on Highway Charging Corridors: Kartikey Hariyani, ChargeZone

GoodWe India’s Aniket Sawant on Crossing 6 GW Shipments and the Future of Energy Storage

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WATERVILLE, Maine (WABI) – The Alfond Municipal Pool Complex in Waterville cut a ribbon Thursday on a new feature that will save money for the taxpayer through a grant, costing them nothing.
The city’s pool unveiled solar panels that offset about 40% of the pool’s energy costs after seeking out innovative ways to both save money for Waterville and reduce greenhouse gas emisisons.
The grant came out of the governor’s office with installation coming around two months ago ahead of the summer season.
The project used $25,000 of the $70,000 dollar grant and organizers are hoping this inspires to families and municipalities to the use of renewable energy in the future.
“I think this is a great project to show other municipalities and folks that live in other municipalities that come to the pool, the potential of this stuff and I think it’s great for other businesses,” commented Community Development Specialist for AYCC Nate Bernard. “That they can see you don’t need to put it in a place that can obstruct anyone’s view. It’s not going to hurt the countrysides. You can put it right on a rooftop, existing infrastructure, and I think that a lot of other municipalities can look at this and see what they can do for themselves to reduce emissions but also save themselves money.”
The pool will officially be open for the season on June 13th.
Copyright 2026 WABI. All rights reserved.

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Hoymiles Microinverters Certified with BEE Rating, Setting a New Benchmark for Solar Efficiency in India  SolarQuarter
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By
Pramod Kumar
Acwa Power, the Saudi Arabian renewable energy company, has leased land in the Philippines to build a 500-megawatt solar plant.
The lease for 500 hectares (5 sq km) in New Clark City, a special economic zone north of Manila, was signed by the company’s Philippine unit to develop a solar photovoltaic and battery energy storage system.
The project involves an estimated minimum investment of $400,000 per megawatt, subject to approvals and phased expansion, the state-owned Philippines News Agency reported.
Philippine finance secretary Frederick Go said Acwa Power’s decision to invest in the country will help unlock new investments, create jobs for Filipinos and foster growth in the Central Luzon region.
In January, the Philippine government-owned Bases Conversion and Development Authority (BCDA) said Acwa Power was investing $200 million to build a large-scale solar energy plant in the country.
New Clark City is a 94 sq km metropolis under BCDA’s management. The company says on its website that it turns former military bases into economic centres through public-private partnerships.
Shares in Acwa Power, which is 44 percent owned by the Saudi Public Investment Fund, rose 3 percent to close at SAR189.5 on Thursday.
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With cybersecurity and energy security concerns increasingly shaping renewable energy policy worldwide, India faces a growing debate over its dependence on imported solar inverters, particularly those sourced from China.
According to the latest report by JMK Research & Analytics, more than 27.5 GW of inverter shipments were recorded in India during the first quarter of 2026 from 19 suppliers of both central and string inverters. In the central inverter segment, Chinese manufacturers accounted for a dominant share, with Sungrow, Sineng Electric, and Hopewind together contributing nearly 85.5% of total shipments. In the string inverter segment, Sungrow, Sineng Electric, and TBEA collectively held around 45.7% of the market.
While growing cybersecurity concerns have prompted the EU to consider restrictions on funding for PV projects using inverters supplied by high-risk vendors like China, experts say India may need a more calibrated approach—one that strengthens security oversight without disrupting solar deployment.
Cybersecurity risks to the national grid
Sonam Chandwani, Managing Partner at KS Legal & Associates, says the primary concern surrounding imported Chinese inverters extends beyond commercial dependence to cybersecurity and strategic vulnerability.
“Modern inverters are intelligent digital systems connected to the grid and capable of remote communication. This raises concerns regarding data access, grid security and excessive dependence on foreign controlled technology in critical infrastructure,” she said.
According to Santosh Jinugu, Partner, Deloitte India, the growing reliance on imported PV inverters in India’s solar farms poses a significant cybersecurity risk to the national grid.
“These inverters are deeply connected to OT, IT and enterprise systems for monitoring and metering and are also linked to the grid through Load Dispatch Centres. This level of connectivity creates potential entry points for cyber threats,” Jinugu said.
Jinugu noted that there is a real risk that imported inverters may contain backdoors, such as embedded IoT components with radio or 4G/5G capabilities capable of communicating with external systems. Such modules can be extremely difficult to detect due to their size and packaging and could potentially be exploited to remotely disrupt power generation.
Teppo Hemiä, founder & CEO, Wirepas, said that as energy systems become increasingly digital and interconnected, cybersecurity must be treated as a foundational requirement for grid resilience and operational continuity.
“Potential vulnerabilities in connected energy infrastructure can arise from several areas, including insecure remote access mechanisms, weak authentication or credential management, unpatched firmware or software, unsecured communication interfaces, insufficient network segmentation, lack of visibility into connected devices and data flows and vulnerabilities introduced through third-party integrations across the supply chain,” Hemiä said, before adding that in large-scale industrial and utility environments, cybersecurity must be addressed holistically across devices, connectivity, cloud systems and operational processes.
Existing regulations
India has progressively tightened quality and compliance requirements for solar inverters.
Megha Arora, Partner at CMS INDUSLAW, said inverter procurement for government-funded and subsidised solar projects in India is increasingly regulated through a combination of quality-control requirements, localisation preferences and cybersecurity mandates.
“Under the Solar Systems, Devices and Components Goods Order, 2025 issued by the Ministry of New and Renewable Energy (MNRE), Bureau of Indian Standards (BIS) certification is mandatory for all solar inverters supplied in India, including off-grid, grid-tied, and hybrid inverters. Manufacturers are required to comply with Indian Standards such as IS 16221 (Part 2):2015 and IS 16169:2019, with model-wise efficiency testing also mandated under applicable standards. Products manufactured at different facilities must undergo separate testing and mandatory marking requirements apply,” Arora said.
“In parallel, the Bureau of Energy Efficiency (BEE) introduced a Standards and Labeling Programme for grid-connected solar inverters.
“Further, in July 2025, the MNRE issued cybersecurity compliance requirements under the PM Surya Ghar: Muft Bijli Yojana mandating that inverter communication devices connect only to national servers managed by the government or designated agencies. The use of communication systems transmitting data to foreign servers has been discouraged on cybersecurity and energy-security grounds.”
While India has not introduced an ALMM-style domestic content mandate specifically for inverters, government procurement increasingly favours local manufacturing.
“SECI tenders often require procurement from “Class-I local suppliers” under the Public Procurement (Preference to Make in India) Order, 2017, which generally requires at least 50% local content. In addition, bidders from countries sharing a land border with India remain subject to registration restrictions under Rule 144(xi) of the General Financial Rules,” said Arora.
Gaps remain
Government procurement frameworks already provide tools to impose technical standards, data localisation requirements, and trusted-vendor criteria without imposing an outright prohibition on Chinese-make inverters. Experts, however, highlight important gaps remain in the current regulatory framework.
According to Jinugu, while India’s current testing procedures under Bureau of Indian Standards (BIS) and Compulsory Registration Scheme (CRS) evaluate safety, grid compatibility, and efficiency, these don’t adequately address cybersecurity risks.
“Although importers are required to submit Construction Data Forms and Critical Component Lists to disclose internal components, these mechanisms rely on self-reporting and can be circumvented if malicious components are intentionally omitted,” he said.
Jinugu proposed that the government should make sure that all OEMs and importers abide by IEC 62443-4-1, which focuses on secure product development lifecycle (the process), and IEC 62443-4-2 technical security requirements. He believes that strengthening these measures will be essential to safeguard India’s power infrastructure from evolving cyber threats.”
Is a European-style restriction feasible?
Experts caution that India may not yet be in a position to adopt restrictions similar to those being considered in parts of Europe.
Chinese manufacturers dominate inverter shipments to India because of their technological maturity, large-scale manufacturing ecosystems and competitive pricing.
Arora highlights that India’s domestic inverter manufacturing ecosystem remains underdeveloped relative to the scale of the country’s rapidly growing solar market, particularly in advanced utility-scale inverter technology.
India’s cumulative installed solar capacity crossed approximately 150 GW by March 2026, with over 44 GW added during FY 2025–26 alone. This pace of deployment has created a substantial demand for solar inverters and related power-electronics equipment.
“Chinese manufacturers have dominated the Indian inverter market for several years due to their economies of scale, mature manufacturing ecosystems, and advanced power-electronics technology. This cost advantage is particularly important in India because utility-scale solar projects are awarded through highly competitive tariff-based bidding processes where reducing capital costs is critical,” said Arora. “The same commercial logic that enabled Chinese dominance in solar modules applies even more strongly in the inverter segment, where India’s domestic manufacturing capacity is considerably weaker.”
“Inverter manufacturing requires advanced electronics, semiconductor integration and strong research capability,” Chandwani added. “Chinese companies dominate because they have scale, pricing advantages, mature supply chains and proven technology. India has growing manufacturing potential but still depends heavily on imported components and technology.”
Chandwani said that domestic companies are improving, but replacing Chinese dominance immediately would be commercially difficult.
Phased approach favoured
Industry experts see the complete localization of inverter technology as a medium- to long-term objective rather than a near-term possibility. According to them, an immediate restriction on Chinese inverters could create supply-chain disruptions and increase project costs at a time when India is chasing ambitious renewable energy targets.
Chandwani argues that a phased regulatory framework would be more practical and legally sustainable than a sudden prohibition.
“India should avoid an abrupt blanket ban similar to the restrictions being considered in parts of Europe because the domestic ecosystem is not yet fully prepared to replace Chinese suppliers at scale,” she added. “However, India is justified in imposing stricter cybersecurity audits, trusted vendor requirements, phased localisation norms and restrictions for sensitive government projects.”
Rather than specific geopolitical measures or vendor restrictions, Hemiä believes the priority should be establishing strong cybersecurity and resilience requirements applicable across all critical infrastructure technologies and suppliers.
Building resilient, interoperable and secure infrastructure ecosystems is essential to supporting long-term operational continuity and energy security.
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The window to claim a 30% tax credit on your solar panel project is closing July 4th, which means you’ve got just one month left to safe harbor your project and preserve your eligibility – keep reading to find out how.
Under the IRS “safe harbor” rules, taxpayers can preserve their eligibility for certain incentives and credits by committing to a project before the incentive deadline expires, even if the project won’t be fully completed until months later. With just one month remaining before the solar tax credits expire, understanding how safe harbor works could mean the difference between thousands of dollars in tax savings and missing out entirely.
Those safe harbor rules are laid out fully in IRS Notice 2018-59, which lays out the full details of what’s allowed and what isn’t. As you read through it, pay close attention to section 3:
SECTION 3. METHODS FOR ESTABLISHING BEGINNING OF CONSTRUCTION

.01 In general. This notice provides two methods for a taxpayer to establish that
construction of energy property has begun for purposes of the ITC under § 48. A
taxpayer may establish the beginning of construction by starting physical work of a
significant nature as set forth in section 4 of this notice (Physical Work Test).
Alternatively, a taxpayer may establish the beginning of construction by meeting a safe
harbor based on having paid or incurred five percent or more of the total cost of the
energy property as set forth in section 5 of this notice (Five Percent Safe Harbor).

Both methods require that a taxpayer make continuous progress towards
completion once construction has begun (Continuity Requirement). Section 6 of this
notice discusses the Continuity Requirement and provides a safe harbor for satisfying
this requirement (Continuity Safe Harbor).
IRS N-18-59
We covered some of these topics and touched on Section 48E of the Federal tax code last month. You can read that original article in full – along with a comprehensive disclaimer reminding you that I am absolutely not an accountant – below.
SKIP THE STORY: I’m ready to start now!
The Trump Administration’s decision to repeal of the 30% home solar tax credit in 2025 looked like the end of the road for subsidized residential rooftop solar projects, but homeowners can still get it under certain circumstances – until America’s 250th birthday, that is.
The 30% federal tax credit (Section 25D) for residential solar is, of course, still dead. The credit was very publicly expired on December 31st, 2025 — but that just meant you couldn’t get that 30% back for systems you bought. See, Section 25D (the one that the Trump Administration killed) only applied to taxpayers with an ownership interest in their PV systems, but leases?
Leases are still on the table, though. And – just as we’ve seen with electric vehicle tax credits over the years, the rules for leases are a little bit different than those for purchases.
What that means for home solar is that, under Section 48E of the Federal tax code, qualified solar companies that own a PV system can continue to claim a credit of up to 30% on those through the end of 2027, and if you’re leasing your system or entering into a power-purchase agreement (PPA) with a solar installer, the company can pass some or all of that incentive on to you. The “catch” is that they can only pass along tax credits they actually recieve, and while while Section 48E technically survives through the end of 2027, many solar companies are racing to “safe harbor” projects before July 4, 2026 – the date many in the industry see as the last meaningful chance to lock in the full 30% credit.
The new federal bill sets strict deadlines for commercial solar projects to receive the full 30% tax credit. Projects that begin construction by July 4, 2026 must be placed in service within four calendar years. For projects that begin construction after July 4, 2026, the credit is only available if the project is placed in service by December 31, 2027.
STRAIGHT UP SOLAR
That July-December window is pretty tight, and is likely to seem even tighter if a prolonged conflict in Iran creates a larger impact on global shipping and supply chains. That said, for solar projects initiated before the big 250th party, the 30% solar tax credit could mean a lower monthly payment on a lease or PPA, or even totally eliminated up-front costs.
Those details are ultimately between you and the company you decide to move forward with. The key takeaway, however, is that the 30% solar incentive isn’t dead dead. It’s just mostly dead – and if you’re shopping for solar, sooner is going to be a lot better for you than later.
At the center of the post-2025 solar tax credit is US Code § 48E, often called the Clean Electricity Investment Credit. Unlike the now-expired residential credit (the previously-mentioned Section 25D), which was claimed directly by homeowners, Section 48E is a commercial investment tax credit designed to incentivize businesses that own “clean energy equipment,” which currently includes both solar panels and battery energy storage systems (along with natural gas fuel cells, among other things).
Under this provision, a company that owns a solar installation can claim a tax credit worth up to 30% of its qualified investment in the project then enter into a third-party ownership model (lease or PPA) with the homeowner.
As the July 4th safe haven cutoff date indicates above, however, there are some caveats here that could complicate your particular installation – which allows me to segue nicely into the following disclaimer …
Tax law is a messy, complicated, and high-stakes field. Federal tax credits, state laws, utility programs, and the fine print in the contracts from company to company can overlap or even contradict each other, and navigating any part of it isn’t especially intuitive. That complexity is exactly why the smart people you know hire accountants and tax professionals to make incentives work for them, and you should do the same.
If you’re considering a lease or PPA, a conversation with a qualified professional installer can help you understand what’s being offered and how a given deal is being structured. Take that information to your accountant to understand what’s real, what’s marketing, and what actually saves you money.
Finally, if there’s money on the table, make sure you don’t leave it there! Remember: US tax law could be a single line codified into law. Instead, it’s 4,000+ pages of densely worded legalese. Get you an expert, and get what your democratically elected leaders decided you have coming to you.
Unless, you know, you actually don’t care about money!
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Published by Bdaily Bdaily Business News on 04 Jun 2026
A quarry operator is cutting energy costs and strengthening its security of supply after switching on a new floating solar farm.
Edinburgh-based Nova has delivered a 400kW floating photovoltaic array for Bathgate Silica Sand at its Arclid Quarry site in Sandbach, Cheshire.
The project, installed on North Arclid Lake, features 650 floating solar panels and has a footprint equivalent to two Olympic swimming pools.
The array is now generating clean electricity for Bathgate Silica Sand’s quarry operations, helping the company reduce energy bills and progress its decarbonisation plans while preserving valuable operational land.
Nova delivered the scheme in six months, from feasibility and design through to consents, installation and operation, with first power achieved in May after the engineering, procurement and construction contract was awarded in December.
The project was developed in partnership with multidisciplinary environmental and engineering consultancyRSK Group and builds on Nova’s experience in marine energy, including the world’s first offshore tidal array in Shetland and Scotland’s first floating solar project.

Simon Forrest, chief executive at Nova, said: “Achieving first power at the Cheshire quarry is a significant milestone and a testament to our team, who delivered this project in just six months. 
“The array is already reducing our client’s energy bills. 
“It clearly demonstrates what floating solar can offer to businesses with access to water bodies. 
“We are excited about what this project signals, both for our pipeline and for the role floating solar will play in the UK reaching its 2035 target.”
The development comes as floating solar gains momentum across the UK, with industry reports highlighting its potential to cut bills, increase clean power generation and support energy security.
The Government’s Solar Roadmap has also committed to increasing national solar capacity to 70GW by 2035, with floating solar identified as a technology capable of contributing across lakes, reservoirs, ports and harbours.
David Robinson, managing director of Bathgate Silica Sand, added: “This is a significant moment for our business and shows that quarries are playing a key role in creating a more sustainable future. 
“Many thanks to Nova for delivering on time and managing every aspect of the job, allowing us to focus on our core day-to-day quarrying operations.” 
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A pilot project combining a 27 kW solar PV system with batteries and hydrogen fuel cells is under development at a Chilean scientific base on an Antarctic island.
The project is being developed at the Professor Julio Escudero Scientific Base, operated by the Chilean Antarctic Institute (INACH) on King George Island, which lies around 120 km off the coast of Antarctica.
The initiative is being implemented by the German agency Deutsche Gesellschaft für Internationale Zusammenarbeit (GIZ) as part of the Team Europe Renewable Hydrogen Development (RH2) project, with co-financing from the European Union and Germany’s Federal Ministry for Economic Affairs and Energy (BMWE).
The proposed project aims to test hybrid energy solutions in one of the world’s most demanding operating environments while reducing reliance on fossil fuels in Antarctic infrastructure.
According to the project’s pre-feasibility study, one option under consideration is a 27 kW solar photovoltaic plant using 500 W monocrystalline solar panels. This configuration would generate an estimated 66 kWh per day, 1,980 kWh per month, and 11,880 kWh per six-month season. Given the output of each module, the design would require approximately 54 solar panels. The report also compares this option with a 12 kW wind power plant and an 11 kW optoelectric solar panel system.
On the hydrogen side, the conceptual design envisions on-site hydrogen production using a small electrolyzer with a capacity of approximately 0.5 Nm³/h, equivalent to 1 kg of hydrogen per day, and a nominal electricity consumption of 2.4–5 kW. The study allows for alkaline, PEM, or AEM electrolyzer technologies, as all three meet the pilot project’s requirements.
The hydrogen would be stored as a gas in stationary tanks or cylinders with a minimum capacity of 5 kg and a maximum pressure of 30–40 bar. The stored hydrogen would feed PEM fuel cells designed to provide 30 kW of backup power to the base laboratory for up to two hours per month. Estimated hydrogen consumption for this purpose is 4.14 kg per month, 25 kg per operating season, and 50 kg per year.
The electricity generated by the fuel cells would require a 30 kW inverter and an automatic transfer switchboard to isolate and directly power the laboratory in the event of a power outage. The system design also includes hydrogen leak sensors, alarm systems, emergency shutdown mechanisms, thermal control, air renewal systems, water purification equipment, and stainless-steel piping for hydrogen, water, and oxygen venting.
The project emerged following studies conducted in 2022 and 2023, which assessed the technical and economic feasibility of using hydrogen as a source of electricity and heat under extreme conditions. The analyses concluded that it is feasible to develop a modular system capable of producing, storing, and utilizing renewable hydrogen on-site.
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India has surpassed the United States of America in annual solar capacity additions to become the world’s 2nd largest solar growth market in 2025. India has crossed a remarkable 155 GW of installed solar capacity, helping achieve country’s 50% non-fossil fuel capacity target and fulfil its Nationally Determined Contributions (NDCs) ahead of schedule. Flagship initiatives such as PM Surya Ghar: Muft Bijli Yojana are transforming lives, with over 40 lakh households already empowered through rooftop solar.
 
Highlighting the remarkable achievement, Union Minister for New and Renewable Energy Pralhad Joshi today said that the country’s solar growth story is setting global benchmarks and driving record capacity additions through strong policy support, innovation and world-class infrastructure. He noted that Under the leadership of Prime Minister Narendra Modi India’s clean energy transition is accelerating, strengthening energy security, advancing sustainable development and reinforcing the country’s position as a global leader in renewable energy.
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NTPC Renewable Energy Limited (NREL), a wholly owned subsidiary of NTPC Limited, has floated a tender for an engineering, procurement, and construction (EPC) package for the development of a 300 MW grid-connected solar photovoltaic (PV). The project will be developed near Nokhra in Rajasthan.
According to the tender specifications, the scope of work covers the complete design, engineering, manufacturing, supply, transportation, installation, testing, and commissioning of the solar power plant, including the supply of solar PV modules. It includes site preparation activities such as land grading, vegetation clearing, topographical surveys, and geotechnical investigations. It also covers the construction of foundations, installation of tracker-based module mounting structures, and mounting and interconnection of solar PV modules.
Additionally, the project involves the construction of inverter and switchgear rooms, associated civil and electrical infrastructure, HT cable laying, and grid connectivity up to the 33 kV main pooling switchgear. Other key components include the installation of a module cleaning system, internal roads, drainage networks, temporary fencing, security infrastructure, a weather monitoring station, and a SCADA-based system for remote monitoring and control of the solar power plant.
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November 24, 2025

City of Charlottesville and Charlottesville City Schools Complete Solar System Installation at CATEC

CHARLOTTESVILLE, VA – The City of Charlottesville and Charlottesville City Schools (CCS) announce the completion of a 262.9 kW solar photovoltaic (PV) system on the roof of Charlottesville Area Technical Education Center (CATEC). This system is the largest solar PV system in the City and CCS portfolio.  
This summer, a new solar photovoltaic (PV) system which generates energy from the sun was installed on Charlottesville Area Technical Education Center (CATEC) and is now fully operational. This clean energy project started in May 2025 and was fully operational three months later in August 2025. It is expected this system will produce between 250,000 and 300,000 kWh per year and will meet over 60% of the building’s electricity need. So far, the system has produced over 76 MWh of electricity. 
This climate action project represents a milestone in the City of Charlottesville’s commitment to clean energy adoption and resource conservation, aligning with the City’s community climate goals of reducing emissions 45% by 2030 and aiming for carbon neutrality by 2050. It leverages the City of Charlottesville’s contract with CMTA to design and deliver projects through a Master Energy Performance Contract aimed at improving energy efficiency, reducing water consumption, and decreasing greenhouse gas emissions. CMTA is an energy services company that delivers decarbonization and occupant health and wellness through energy efficient, sustainable projects. 
CMTA teamed with a local solar system installation partner, Tiger Solar, as well as FLIPP Inc, a local nonprofit workforce development organization. Dedicated to fostering an inclusive workforce, FLIPP Inc offers renewable energy training, certification programs, and entrepreneurship development for individuals from disadvantaged backgrounds. This approach reflects the City’s commitment to local businesses and workforce development and intentional collaboration on climate action. 
CATEC is a member of the Community Climate Collaborative’s Green Business Alliance (GBA), a network of Virginia-based businesses committed to reducing greenhouse gas emissions. The installation of this PV system is a major step towards achieving greenhouse gas reductions and utility bill savings at CATEC and demonstrates the organization’s leadership in the community.  
“We’re thrilled to have this system deployed and now producing clean energy, showing students at CATEC firsthand how solar is a lucrative and viable industry to get into. The positive climate impacts, cost savings, and educational benefits made this an extremely important project for the City to pursue,” says Kristel Riddervold, Director of the City’s Office of Sustainability.  
The City is planning for more PV installations across its portfolio of facilities.  
A recent ribbon cutting video is available here: https://www.youtube.com/watch?v=mkH5Ryz-kdY  
More information about the Charlottesville municipal solar portfolio is here: https://www.charlottesville.gov/CitySolar 
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Qualitas Energy, a leading global investment and management platform with a dual focus on both funding and developing renewable energy, energy transition, and sustainable infrastructure, announced today the acquisition of a development-stage solar photovoltaic (PV) project in the United States, with a planned capacity of 164 MWp.
The asset, located in Illinois within the Midcontinent Independent System Operator (MISO) market, has been acquired from Bechtel Enterprises. Notice to Proceed (NTP) is expected in the second quarter of 2028, with Commercial Operation Date (COD) targeted for the third quarter of 2029. The project has 100% site control, is fully permitted and benefits from strong local community support, having received unanimous approval as part of the county permitting process.
Qualitas Energy will leverage its integrated investment, development and asset management capabilities to further de-risk the asset and advance it into its next phases, including the optimisation of offtake strategy, procurement, construction planning and financing. The project also offers additional value creation potential through the future integration of up to 64 MWac of battery energy storage capacity, which could support the structuring of a bundled solar-plus-storage power purchase agreement (PPA), enhancing its commercial flexibility and long-term revenue profile.
In addition, the asset benefits from a favourable interconnection position within the MISO market and offers strong commercial optionality, with access to both the Minnesota and Illinois hubs. This provides a broad range of potential offtake routes, including corporate and industrial customers, hyperscalers, traditional utilities and public renewable energy procurement programmes.
This transaction was undertaken through Qualitas Energy Fund VI, the firm’s latest flagship vehicle, launched at the end of 2025.
“This acquisition reflects Qualitas Energy’s disciplined investment approach and its ability to identify high-quality renewable energy assets with strong value creation potential. The project combines advanced development status, strong fundamentals and multiple commercialisation pathways in one of the country’s most attractive power markets. This transaction also underscores the strategic relevance of the United States for Qualitas Energy,” said Alejandro Ciruelos, Partner – US at Qualitas Energy.
Qualitas Energy was advised by Norton Rose Fulbright (legal), Sargent & Lundy (technical), and Leo Berwick (financial and tax).
About Qualitas Energy
Qualitas Energy is a leading global investment and management platform with a dual focus on both funding and developing renewable energy, energy transition, and sustainable infrastructure. Since 2006, the Qualitas Energy team has dedicated over €14 billion to the energy transition worldwide. These investments have been deployed through six vehicles: Fotowatio / FRV, Vela Energy, Qualitas Energy III, Qualitas Energy IV, Qualitas Energy V, and Qualitas Energy Credit Fund. Qualitas Energy’s existing portfolio currently comprises 11 GW of operational and development-stage renewable energy assets – including solar PV, concentrated solar power (CSP), wind, energy storage, hydroelectric power, and renewable natural gas – across Spain, Germany, the United Kingdom, Italy, Poland, Chile, and the United States. Over the past five years, Qualitas Energy has generated enough energy to supply 1.7 million homes and has successfully avoided the emission of 1.5 million metric tons of CO2 equivalent. The Qualitas Energy team consists of more than 500 professionals across fifteen offices in Madrid, Berlin, London, Milan, Hamburg, Wiesbaden, Trier, Cologne, Stuttgart, Warsaw, Wroclaw, Santiago, Durham, Bristol, and Edinburgh.
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Kansas county approves permit for 1,200-acre solar farm  KSN.com
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MSolar Manufacturing’s plant expected to create 150 jobs
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Solar panel manufacturer to establish $23.78M Shenandoah County facility
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MSolar Manufacturing’s plant expected to create 150 jobs
Josh Janney //June 4, 2026//
Woodbridge-based solar panel startup MSolar Manufacturing plans to invest $23.78 million to establish a manufacturing facility in Shenandoah County that is expected to create 150 jobs, Gov. Abigail Spanberger announced Thursday.
Founded in 2018, MSolar has renovated a vacant warehouse into a 56,000-square-foot facility in Mount Jackson that will produce high-efficiency solar modules for large-scale energy projects. The site is expected to become operational in August.
“By choosing to invest in Mount Jackson, MSolar is creating new career opportunities in the Shenandoah Valley and helping make sure Virginia has the infrastructure to make energy more affordable and reliable for local communities across our commonwealth,” Spanberger said in a statement. “Increasing energy generation is critical to addressing high energy costs and supporting greater economic growth. I congratulate MSolar on this exciting investment and look forward to watching them grow in the Shenandoah Valley.”
According to the governor’s office, the facility will produce solar glass, silicon cells and heterojunction (HJT) cells, which layer different types of silicon, and to assemble finished solar modules. The plant is expected to manufacture more than 500,000 HJT solar panels annually for utility-scale and commercial projects across the United States.
“We’re building the foundation of a vertically integrated solar manufacturing platform here in Virginia,” MSolar CEO Michael O’Connor said in a statement. “This factory represents the first step in our long-term strategy to expand domestic solar production and deliver high-performance technology for energy projects.”
According to O’Connor, MSolar has not yet done any manufacturing. He said the site Spanberger announced will be the first of four  facilities MSolar plans to build in the region within the next four to five years, all within about 8 miles of each other. He said the company will make announcements on the other sites at a later time.
The Virginia Economic Development Partnership worked with Shenandoah County to secure the project and will support MSolar through the three-year Virginia Jobs Investment Program, which provides recruiting and training services as well as cash grant reimbursements for associated human resources costs after a company has had new employees on the payroll for at least 90 days.
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Cooling Techniques Enhance Electrical Performance of Photovoltaic Panels in Hot Climates  AZoCleantech
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Today, as more countries commit to long-term net-zero goals, green and low-carbon development has become a shared global priority. With the accelerated adoption of renewable energy worldwide, scenario-based applications are becoming an important growth point for the photovoltaic market in the next stage.
Driven by cost advantages and clean power output, renewable energy is accelerating the start of a new cycle of scenario-based applications, photovoltaics increasingly deployed in high-consumption, high-cost, and electricity-constrained environments. The need is especially strong in off-grid operations—such as oil and gas extraction and mining – where diesel generation remains costly and inefficient.
According to relevant data, electricity generated from traditional fossil-fuel-based sources—such as coal, natural gas, and diesel—remains significantly more expensive and less flexible than renewable alternatives, while also facing growing environmental constraints.
In particular, the cost of diesel-based power generation is approximately 275% higher than that of photovoltaic power generation. In addition to high fuel costs, diesel generator systems are challenged by limited flexibility, high maintenance requirements, and increasing environmental pressure.
Against this backdrop, there is a clear and growing demand for standardized, mobile solar solutions that can significantly reduce operating costs while improving efficiency and sustainability.

Based on market demand, GCL launched the EcoPower Mate series in November 2025 – a mobile photovoltaic system designed for operations facing constrained or complex energy conditions worldwide. Built for extreme environments, rapid deployment, and high energy efficiency, EcoPower Mate offers a new approach to zero-carbon transformation in traditional high-energy-consuming scenarios.
Tackling Industry Pain Points: Dual Product Configurations Optimized for Diverse Scenarios
Traditional diesel generators have long dominated outdoor operations, yet they come with significant drawbacks – severe carbon emissions and noise pollution, high power generation costs, insufficient deployment flexibility, and difficulty in coping with extreme weather and complex terrain.
To address the aforementioned issues, EcoPower Mate offers two product configurations: wheeled and rail-mounted, covering the needs of different application scenarios.
The wheeled PV container features an integrated design with container doors, built-in inverters, DC junction boxes, power distribution modules, and drive systems. Measuring 12.16m × 2.53m × 2.89m, it is lightweight and highly portable. This product requires no prefabricated tracks and can be deployed on flat surfaces such as concrete or gravel, with local compaction and leveling or driving in short steel stakes, making it ideal for flat terrain and reducing on-site construction work.
The rail-mounted PV system is designed for complex and varied road conditions. It uses a rail foundation equipped with mechanical support arms and secure module-fastening systems. A single rail can be up to 100m long, and the body size is 6.058m × 6.058m × 2.438m. This configuration ensures stable operation in rugged environments typical of oil and gas exploration and mining sites.
Both products are equipped with GCL’s SiRo T series high-efficiency photovoltaic modules, delivering a maximum power output of up to 520 W and a module efficiency of up to 23.37%. The modules are compatible with mainstream inverters on the market and have extremely strong adaptability.
Three Core Values Redefining the Benchmark for Mobile Solar Power
Beyond scenario-specific configurations, EcoPower Mate delivers three key advantages—flexibility, cost efficiency, and environmental performance—setting a new standard for mobile outdoor energy solutions.
EcoPower Mate offers rapid plug-and-play deployment, enabling installation and power generation within minutes—reducing setup time by up to 90% compared with traditional PV installations. In extreme weather conditions, the user can relocate all modules into the container within 30 minutes of receiving the weather alert to provide effective protection against sandstorms, heavy rainfall, and other severe environmental impacts. A smart power management system adjusts output in real time based on load requirements, while the reusable design allows the entire system to be moved easily between sites.

EcoPower Mate helps reduce operational costs through automated installation, cutting labor requirements by more than half. Its reusable design reduces equipment wear by more than 30%, and the self-cleaning function improves the power generation efficiency of the modules by more than 40%. Compared to diesel power generation, solar power can cost as low as USD 0.10–0.12 per kWh—up to 60% lower than diesel generation—offering substantial long-term savings and improved return on investment.
EcoPower Mate also delivers strong environmental benefits. The product operates with low operating noise and no greenhouse gas or air pollutant emissions, supporting operators’ sustainability targets. For industries such as oil and gas, where environmental regulations are tightening, this solution helps reduce carbon footprints and supports broader corporate ESG goals. 
Multi-Scenario Adaptation: Building a Zero-Carbon Energy Ecosystem
With its strong environmental adaptability and system compatibility, supports a wide range of applications, including off-grid, hybrid, and grid-connected systems. It is also compatible with multiple energy storage configurations, enabling flexible deployment across industries seeking to reduce emissions.
In off-grid system scenarios – including, but not limited to, remote islands, mining operations, agricultural and food production sites, outdoor events, and oil and gas facilities—the EcoPower Mate provides a stable and clean alternative to traditional fossil-fuel-based power solutions. In hybrid or grid-connected systems, it can integrate with existing power infrastructure, enhancing energy self-sufficiency and supporting low-carbon industrial operations.
The solution can also support grid-connected applications such as data centers, supplying renewable energy to power high-demand computing operations and contributing to more sustainable digital infrastructure.
EcoPower Mate offers 50 kW and 125 kW energy storage options, both of which can be expanded through parallel configuration. A single system support up to 1 MWp of solar capacity and 1 MWh of storage. When combined in parallel, deployments can scale to 2 MWp of PV, 2.6 MWh of storage, and 1.25 MW of AC output, meeting the needs of larger operations.

The first batch of EcoPower Mate units has completed installation, commissioning, and system testing at GCL’s Hefei factory, with all performance metrics meeting design specifications. The product has officially entered the market application stage.
Looking ahead, the EcoPower Mate will expand internationally, with installations planned in Saudi Arabia in Q1 2026, marking the start of its overseas deployment.
With more than 350 global companies committed to RE100 targets and industries advancing their decarbonisation strategies, EcoPower Mate is positioned to become an essential solution for reducing emissions in energy-intensive operations worldwide.

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Dust-prone desert of the Southwest may be ideal for solar energy  Tech Xplore
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India’s total renewable energy capacity reached 250,519 MW by the end of 2025, according to the International Renewable Energy Agency (IRENA) report Renewable Capacity Statistics 2026. The country added more than 45,000 MW of renewable capacity during 2025, compared to a total installed renewable capacity of 205,390 MW in 2024.
The growth increased the share of renewables in India’s total electricity capacity to 42.8% in 2025, up from 38.4% a year earlier.
Solar leads additions
Solar photovoltaic (PV) remained the main contributor to India’s renewable energy expansion. Installed solar capacity rose to 135,159 MW in 2025 from 98,139 MW in 2024, reflecting an addition of about 37,020 MW during the year.
According to IRENA data, India added more than 37 GW of solar capacity in 2025, surpassing the United States, which added 34 GW during the same period. The report positions India as the world’s second-largest solar growth market.
Union Environment Minister Bhupender Yadav said India’s solar capacity additions reflected the country’s accelerating clean energy transition and expanding renewable energy infrastructure.
Wind and hydro growth
Wind energy capacity increased to 54,511 MW in 2025 from 48,163 MW in 2024.
Renewable hydropower capacity, including mixed plants, rose to 56,299 MW, compared to 52,254 MW in the previous year.
Solid biofuels capacity stood at about 10,942 MW in 2025. The report noted that bagasse capacity was not separately reported and aligned closely with the overall solid biofuels figure.
Global renewable additions
Globally, renewable energy accounted for 49.4% of installed power capacity by the end of 2025, up from 46.3% in 2024.
The world added a record 692 GW of renewable energy capacity during the year, including 510 GW from solar alone. Total global renewable energy capacity reached 5,149,280 MW.
The report noted that renewable energy deployment remained concentrated, with China, the United States, and the European Union accounting for 79.5% of new renewable capacity additions in 2025.
The featured photograph is for representation only.
The central government’s Rs 20,000 crore mega solar power project connecting Ladakh to Haryana has sparked growing opposition from environmentalists and local groups in Himachal Pradesh, who warn it could cause irreversible ecological damage in the fragile Himalayan region. The project involves setting up a 713-km high-voltage direct current (HVDC) transmission line from Pang in…
Read More Opposition grows to Rs 20,000 crore Ladakh–Haryana solar transmission project
Ahasolar Technologies Limited has received a consultancy work order worth about Rs 1.18 crore for a major solar power project in Rajasthan. The contract has been issued by CIL Rajasthan Akshay Urja Limited for providing Owner’s Engineering and Project Management Consultancy (OEPMC) services. The assignment covers an 875 MW solar photovoltaic project located in the…
Read More Ahasolar wins consultancy contract for 875 MW Rajasthan solar project
The Ministry of New and Renewable Energy (MNRE) issued a clarification on 6 August 2025 regarding its revised guidelines for prototype wind turbine installations. The clarification pertains to clause 1(ii)(e) of the guidelines released on 12 June 2025. MNRE stated that the National Institute of Wind Energy (NIWE) may issue revised grid synchronisation recommendation letters…
Read More MNRE clarifies prototype wind turbine guideline for NIWE approvals
The Ministry of Power (MoP) has revised Minimum Local Content (MLC) requirements for Line Commutated Converter (LCC)-type High Voltage Direct Current (HVDC) substations, replacing the earlier flat 60% mandate with a phased schedule extending to 2035. The order, dated April 30, 2026, amends a 2021 notification issued under the Public Procurement (Preference to Make in…
Read More MoP phases local content norms for LCC-HVDC substations to 2035
Adani Group has announced plans to invest between USD 15–20 billion annually over the next five years to expand its total power generation capacity to 100 GW by 2030. The company is pursuing a diversified mix of thermal, renewable, and pumped hydro energy sources to meet this goal. In 2024–25, Adani Group invested over USD…
Read More Adani to invest up to USD 20 billion yearly for 100 GW by 2030
TPG Rise Climate, the climate investment arm of TPG, is in discussions to acquire US-based solar developer Altus Power, according to Reuters sources.  The deal, which could be formalized in the coming weeks, is not yet finalized, and there is still a possibility of no transaction occurring. Altus Power, a leading clean energy provider for…
Read More TPG Rise Climate in talks to acquire Altus Power
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Godfrey Officials Weigh Promoting Solar Program  RiverBender.com
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Research points to lower maintenance costs and strong performance outlook for solar facilities near White Sands despite dusty panels
University of Texas at El Paso
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German Rodriguez Ortiz, a doctoral graduate of UTEP’s Environmental Science and Engineering Program, is the lead author of a study that found solar panels at the Brackish Groundwater National Desalination Research Facility in Alamogordo—a region frequently affected by dust storms carrying particles from the White Sands gypsum dune field—lose power output from dust accumulation at a rate far lower than that of solar facilities in comparable desert regions worldwide. The study was published in the journal Atmosphere in April 2026.
Credit: The University of Texas at El Paso.
EL PASO, Texas (June 4, 2026) – Solar energy developers eyeing parts of southern New Mexico may have less to worry about than expected when it comes to dust. A new study led by University of Texas at El Paso researchers concludes that photovoltaic panels in Alamogordo — a region battered by frequent dust storms carrying particles from the White Sands gypsum dune field — lose only about 2 to 3 percent of their power output to dust accumulation, a rate far lower than that of solar facilities in comparable desert regions worldwide.
The findings, published in the journal Atmosphere in April 2026, carry direct implications for the economics of solar energy in the Chihuahuan Desert, the team said. Because dust-related losses at the study site are modest, and because light rainfall proved sufficient to restore panel performance, operators of solar facilities in the area may be able to clean their panels far less frequently than those at sites in the Middle East, Iran, or China — where soiling losses can reach 10 to 80 percent.
"What we found is that this location is genuinely favorable for solar energy, not just because of its abundant sunshine but because of how the dust behaves here," said German Rodriguez Ortiz, the study's lead author and a doctoral graduate of UTEP's Environmental Science and Engineering Program. "The wind that brings dust from White Sands also helps clean the panels, and the gypsum itself appears to be less harmful to performance than the types of dust studied at other sites globally."
Two natural factors appear to work in the region's favor. Prevailing south-to-southwest winds strike the front face of south-facing panels directly, physically dislodging accumulated particles in a passive cleaning effect. Additionally, rainfall as light as 2.2 millimeters per hour was sufficient to restore panels to near-baseline performance — a lower cleaning threshold than has been documented in California, India and other solar markets. The anti-reflective coating on the panels studied may have contributed to rain's effectiveness, pointing to a potential design consideration for future installations.
The study also found that gypsum — the distinctive mineral blown from White Sands — absorbs less light than other common dust minerals, meaning its optical interference with panel performance is inherently limited. That characteristic, combined with the region's wind patterns and responsiveness to rain, positions the southern Tularosa Basin as a location where the solar resource and the operating environment are better aligned than previously understood, Rodriguez Ortiz said.
These factors lead to a reduced cleaning frequency, which translates into lower water consumption, less labor and meaningfully lower long-term operating costs, the team said.
"This research demonstrates the kind of place-based science UTEP is uniquely positioned to conduct," said Thomas E. Gill, Ph.D., professor of earth, environmental and resource sciences, co-author of the study and Rodriguez Ortiz’s doctoral advisor. "Our location in the Chihuahuan Desert is not just a backdrop — it is a living laboratory, and this work shows how deeply understanding your local environment can generate insights with real economic and energy consequences for the region."
The study was conducted at the United States Bureau of Reclamation's Brackish Groundwater National Desalination Research Facility in Alamogordo, where the team monitored six solar panels across three sampling periods from late 2022 through spring 2024, recording 22 dust events in the process. Co-authors include assistant professor of chemistry and biochemistry Jose A. Hernandez-Viezcas, Ph.D.; UTEP researcher Alejandro J. Metta-Magana; and alumna Malynda Cappelle, Ph.D., of the Bureau of Reclamation.
The researchers recommend longer-term monitoring to capture seasonal variation through the summer monsoon and more and less dusty periods, and more detailed investigations into optimal cleaning practices.
About The University of Texas at El Paso
The University of Texas at El Paso is America's leading Hispanic-serving university. Located at the westernmost tip of Texas, where three states and two countries converge along the Rio Grande, 84% of our 26,000 students are Hispanic, and more than half are the first in their families to go to college. With respect to research, UTEP is in the top 5% of universities in America and offers 169 bachelor's, master's and doctoral degree programs at the only open-access, top-tier research university in America.
10.3390/atmos17050442
Experimental Investigation of Photovoltaic Soiling from White Sands Dust in Alamogordo, New Mexico, USA
26-Apr-2026
Disclaimer: AAAS and EurekAlert! are not responsible for the accuracy of news releases posted to EurekAlert! by contributing institutions or for the use of any information through the EurekAlert system.
Media Contact
Victor Arreola
University of Texas at El Paso
varreola1@utep.edu
Office: 915-747-6437

University of Texas at El Paso


Copyright © 2026 by the American Association for the Advancement of Science (AAAS)
Copyright © 2026 by the American Association for the Advancement of Science (AAAS)

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In the sun-soaked expanse of Alamogordo, New Mexico, a groundbreaking study has unveiled encouraging news for solar energy developers aiming to harness the abundant sunshine in the region. Despite the area’s frequent dust storms, propelled by particles from the notorious White Sands gypsum dune field, photovoltaic panels installed at the Brackish Groundwater National Desalination Research Facility demonstrate remarkable resilience. According to research published in the journal Atmosphere in April 2026, these panels experience an unexpectedly low power output loss—only about 2 to 3 percent—due to dust accumulation, a figure that significantly undercuts the soiling rates reported in solar facilities situated in other dusty desert regions across the globe.
This revelation carries profound implications for the economics and operational sustainability of solar energy in arid environments, particularly within the Chihuahuan Desert. Commonly, soiling losses in harsh desert climates can drain solar panel efficiency by anywhere from 10 to a staggering 80 percent, precipitating frequent and costly cleaning regimes. However, the Alamogordo site’s natural conditions appear to inherently mitigate these losses, suggesting that operators could substantially reduce cleaning frequency. This reduction would not only curb water consumption—a critical consideration in water-scarce desert locales—but also decrease labor and operational expenses, enhancing the long-term viability of solar installations.
The study’s lead author, Dr. German Rodriguez Ortiz, a doctoral alumnus of the University of Texas at El Paso’s Environmental Science and Engineering Program, explains that the combination of local meteorology and mineralogy uniquely favors panel performance. “The persistent south-to-southwest winds that sweep over the region directly impact the orientation of south-facing panels, physically dislodging dust particles in a passive yet effective cleaning mechanism,” he stated. Such wind-aided self-cleaning is complemented by sporadic yet sufficient rainfall events, which were observed to restore panel efficiency almost to baseline levels with as little as 2.2 millimeters per hour of precipitation—a much lighter rain threshold than has been documented in other solar markets like California, India, or parts of Asia.
Beyond meteorological influences, the mineralogical composition of the soiling dust plays a pivotal role. The gypsum particles originating from White Sands possess distinct optical properties that limit their interference with photovoltaic energy capture. Unlike the more opaque or chemically aggressive dust types found in Middle Eastern or East Asian deserts, gypsum exhibits higher light transmittance and refractive characteristics that translate into diminished light scattering and absorption on solar surfaces. This intrinsic quality reduces the detrimental impact on solar cell efficiency, making the region’s dust inherently less harmful from a photovoltaic perspective.
To test these multifaceted interactions, the researchers installed six photovoltaic panels and monitored their performance and soiling conditions through a span of three separate sampling periods between late 2022 and spring 2024. During this time, they documented 22 distinct dust events, carefully quantifying the onset, accumulation, and dissipation of particulate matter on the panels. The detailed temporal data elucidated how quickly soiling impacted power output and how effectively natural factors restored functionality without human intervention.
Crucially, the study also explored the influence of the anti-reflective coatings on the panels used. These coatings, integral to modern photovoltaic technology, not only increase light absorption but may also enhance the efficacy of rainwater in washing away dust. The synergy between coating technology and the region’s hydrometeorological conditions suggests that future solar panel designs for dusty deserts might prioritize specialized surface treatments that optimize passive cleaning dynamics, further reducing maintenance demands.
This research underscores the necessity of place-based environmental science in renewable energy deployment. As Dr. Thomas E. Gill, professor of earth, environmental, and resource sciences and co-author of the study, emphasizes, “Our location within the Chihuahuan Desert serves not just as a geographic backdrop but as a dynamic natural laboratory. The localized insights derived here offer critical understanding that can directly inform energy strategies tailored to the specific challenges and advantages of regional climates.”
A key takeaway from this study is the interdependence of site-specific environmental factors that can beneficially influence the operational efficiency of solar energy infrastructure. Prevailing wind directions, rainfall patterns, dust mineralogy, and cutting-edge panel technology all converge to create a uniquely conducive solar energy environment in the southern Tularosa Basin. These insights challenge the prevailing assumption that desert dust universally imperils photovoltaic output, offering a more nuanced perspective on solar viability in marginal environments.
Moreover, the reduced necessity for frequent cleaning not only conserves precious water but also diminishes labor and operational costs, two significant contributors to the total cost of solar energy production. This efficient balance between natural cleaning processes and technological resilience could serve as a model for solar developers evaluating similar sites worldwide.
The study also opens avenues for future inquiries. Extended monitoring through different seasonal phases—especially during the summer monsoon period notorious for fluctuating dust dynamics—will be critical to fully characterizing long-term soiling behavior. Additionally, optimization of cleaning protocols that leverage natural wind and rainfall events could further streamline solar farm maintenance, enhancing both sustainability and profitability.
Collaborators on this research included esteemed faculty and researchers from multiple disciplines, reflecting the study’s interdisciplinary nature. Apart from Dr. Ortiz and Dr. Gill, contributions came from Assistant Professor Jose A. Hernandez-Viezcas specializing in chemistry and biochemistry, research scientist Alejandro J. Metta-Magana, and alumna Dr. Malynda Cappelle from the Bureau of Reclamation. This collective expertise underpins the robust analytical rigor and comprehensive scope of the findings.
The testing grounds for this work—the United States Bureau of Reclamation’s Brackish Groundwater National Desalination Research Facility—highlight the strategic synergies between water management and renewable energy research. Understanding how environmental parameters affect solar power generation within complex arid ecosystems could inform integrated resource management frameworks capable of advancing both water sustainability and clean energy deployment.
As the global push toward renewable energy intensifies, regionally attuned research like that emerging from Alamogordo intensifies the importance of understanding the unique interplay of environmental factors on solar energy infrastructures. Harnessing these insights promises smarter, more efficient solar technology integration, transforming not just the desert landscape but the broader energy paradigm globally.
Subject of Research: Photovoltaic power output losses due to dust soiling in a gypsum-dust-prone desert environment.
Article Title: Experimental Investigation of Photovoltaic Soiling from White Sands Dust in Alamogordo, New Mexico, USA
News Publication Date: June 4, 2026
Web References:
https://www.mdpi.com/2073-4433/17/5/442
http://dx.doi.org/10.3390/atmos17050442
Image Credits: The University of Texas at El Paso
Keywords
Solar energy, Environmental engineering, Renewable energy, Energy resources, Electrical power generation, Climate zones, Soil science
Tags: Brackish Groundwater Desalination Facility studyChihuahuan Desert solar potentialdesert solar power economicslow soiling loss solar panelsphotovoltaic panel dust resiliencesolar energy in dusty desertssolar energy sustainability in arid regionssolar panel maintenance reductionsolar power efficiency in dust stormsSouthwestern US solar energy researchwater-saving solar energy solutionsWhite Sands gypsum dunes impact
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A new dawn for Chinese solar  Politico
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The continental U.S. added nearly 28 GW of new electric power generation capacity during the 6 months ending in March 2026, according to the latest edition of the Hitachi Energy Grid Pulse, an industry report that analyzes macro-level trends in electricity demand, grid load growth, and the addition of new power-generating resources across regional electrical grids.
Capacity additions were dominated by solar, wind and battery energy storage systems (BESS), with 13.2 GW of solar, 7.8 GW of BESS and 4 GW of wind added. Fossil gas, oil and other sources accounted for 3.4 GW of new capacity across the lower 48 states.
The additions brought the generation capacity represented by solar and wind to an all-time high of 24% of total installed capacity. However, generation from these sources contributed only 18% of all electricity produced, with the difference in capacity vs. generation due to the intermittent nature of the two renewable sources.
The report also tracked load growth across the country’s major transmission regions during the time period, with nationwide demand for electricity estimated to rise by 2% over the same six-month period the year prior. 
Demand in the region served by the Electric Reliability Council of Texas (EROCT) led the nation, growing by 9% year-over-year; something the report’s authors attributed largely to data center demand.
During a media call about the report, Hitachi Energy advisor Debashis Bose noted that peak demand in ERCOT — historically around 90 gigawatts, was forecasted to increase to as much as 148 GW by 2030. “It’s growing more than 50% in the next few years, so the growth rate is pretty phenomenal,” Bose said, adding, “what we are seeing here is… trends are already starting to pop up.”
Texas also led state capacity additions, accounting for just over 6.8 GW. In all six states accounted for 50% of new capacity additions. These states and their added capacities were:
Planned data centers and capacity additions
The Hitachi report included the U.S. map graphic shown above, indicating the states in which the highest number of data centers are planned and under construction includes Virginia, Texas, California, Arizona and Oregon.
Across the country, states add an average of 7.3 MW in capacity for each new data center planned. Texas, California and Arizona all exceed that standard, with 12.1, 8.4, and 11.4 MW of new capacity per data center, respectively.  
As Virginia and Oregon are not represented among the top states for capacity additions, their average capacity additions per planned data center are much lower — 0.29 MW per data center in the former state and just 0.1 MW per data center in the latter.

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By: Andrew Seale June 4, 2026
Soaring silver prices and surging solar demand are forcing panel manufacturers to rethink how much of the white metal goes into every cell. But analysts warn the efficiency gains may not be enough to offset a structural squeeze. 
Silver demand has been consistently outpacing supply for the last six years, with the Silver Institute’s World Silver Survey 2026 projecting a 46.3-million oz. deficit. Tightened physical supply alongside geopolitical uncertainty and investment demand helped silver briefly top $120 per oz. in January from $30 an oz. a year earlier before pulling back. The price was around $74 per oz. on Thursday. 
“Silver at $80 really encourages a very aggressive move for thrifting [and] outright substitution in favour of copper,” Philip Newman, managing director of London-based consultancy Metals Focus, which researches the World Silver Survey, said in an interview. Thrifting refers to using less silver per panel without reducing performance. 
According to the Silver Institute, which published the World Silver Survey 2026, silver use in photovoltaics fell 6% last year to 186.6 million oz. and is forecast to decline a further 19% in 2026 to around 151 million ounces. 
Photovoltaics, the largest industrial source of silver consumption, have emerged as a key driver of demand growth in recent years, helping push the market into repeated deficits. Between 2020 and 2024, silver use in photovoltaic applications more than doubled to roughly 197 million oz., up from about 82 million ounces.  
That surge also triggered a rapid response from manufacturers. The rise in silver prices pushed the metal’s share of solar cell costs from roughly 8% to more than 20%, accelerating efforts to reduce silver loadings and preserve margins. 
However, thrifting may not be enough to curb demand. In North America, policy support and utility-scale buildout drove photovoltaic installations in 2025. U.S. demand for silver powder used in solar manufacturing rose 4% year over year, according to the World Silver Survey. 
Momentum is expected to slow in 2026 as global installations flatten, with some banks and insurers also pulling back financing and coverage amid uncertainty over subsidy eligibility and evolving trade rules tied to China-linked supply chains. 
China remains the key swing factor. The country accounts for roughly 80% of global solar manufacturing capacity, while firms including LONGi and Trina Solar expanded aggressively into the U.S. after the Biden administration’s 2022 clean-energy incentives helped trigger roughly $43 billion in announced solar manufacturing investment and an estimated 48,000 jobs. 
However, new U.S. rules limiting Chinese ownership and control in subsidized factories have created regulatory uncertainty, prompting some buyers, lenders and insurers to avoid China-linked projects. 
Installations in China hit a record 315 GW in 2025, though activity was heavily front-loaded as developers rushed to meet policy deadlines before slowing later in the year amid grid constraints and weaker pricing conditions. 
On the manufacturing side, some Chinese producers shifted capacity offshore in response to U.S. tariffs and trade restrictions, while demand from emerging markets continued to support output growth. China’s solar market is expected to cool in 2026 as policy support normalizes and overcapacity pressures persist. 
Thrifting has played a major role in moderating solar demand for the precious metal in panel manufacturing. “It varies considerably by year, but even when prices were very low, there was an element of thrifting,” metals consultant Newman said. 
However, the process has accelerated over the last two years. Manufacturers are refining how silver paste is applied inside solar cells and adjusting cell layouts to reduce the amount needed, cutting silver use by around 10% compared with earlier designs. New “zero busbar” techniques and ultra-fine printing methods can reduce silver use by another 10% to 20%. 
Production has also shifted towards TOPCon cells, a newer high-efficiency solar technology now dominant in China. The technology improves electrical efficiency inside the cell. 
Other companies are developing copper electroplating and pure copper pastes that could further reduce silver use. 
The industry expects average silver loadings in mainstream photovoltaic cells to fall below 5 milligrams per watt by 2027, according to World Silver Survey data. 
While there are ways to reduce silver use, Robert Godin, co-lead of the University of British Columbia Okanagan’s solar energy research cluster, said the technology remains difficult to scale. He said that while substituting with copper could decrease the amount of silver per module by tenfold (90%), silver is still relatively cheap compared with more advanced alternatives. 
The properties of silver make it good at this job, Godin told The Northern Miner. “It works, it’s cheap, and people are not looking too hard at changing that process.” 
Godin said that while reducing silver amid rising prices and supply deficits is driving the thrifting and substitution narrative, removing silver from the process is a low priority on the research and development side. There are also design barriers to how far efficiency can be pushed. 
“There are some hard physical limits that we’re getting pretty close to,” he said. “But [panels] can definitely be twice as cheap.” 
Policy signals in the U.S. have added another layer of uncertainty, as the Trump administration moves to scale back parts of the federal energy transition agenda while maintaining support for domestic industrial buildout and grid reliability.  
The result is a more selective policy environment, with clean-energy projects increasingly shaped by financing conditions, subsidy eligibility and trade exposure rather than broad deployment targets. 
Ian Lange, an economist at the Colorado School of Mines’ Payne Institute for Public Policy, said that disconnect is often missed in transition planning. Most models assume deployment targets are met and then work backwards into material demand, Lange said. In reality, he said, higher input costs feed directly into build decisions.  
“If silver is higher, we just don’t install as many solar panels,” Lange said. 
That creates a feedback loop between commodity markets and deployment that is often absent from energy transition forecasts, where mineral inputs are treated as scalable rather than price sensitive. For silver, that means demand is not a straight line from installed capacity. 
Thrifting and substitution are reducing the metal intensity per panel, but price signals are also shaping how many projects get built in the first place. Outside solar, structural demand growth is still coming from grid expansion, automotive applications and AI-driven power demand, which continue to underpin industrial consumption. 
Lange said silver’s designation as a critical mineral should drive research and innovation. “Within the U.S. federal system, the criticality is really supposed to be a marker for let’s find a substitute,” Lange said. “That’s supposed to direct federal research dollars [but] I’ll say I haven’t seen good evidence that it actually does that.” 
The World Silver Survey forecasts industrial fabrication to decline by 2%this year, to a four-year low of around 650 million ounces. Newman points out that photovoltaics are the most volatile area of silver demand. 
The policy backdrop has also shifted the tone of the solar buildout itself. What was once largely framed through decarbonization is increasingly being driven by energy security and supply-chain resilience.  
“When we put the survey together back in late March, we had to make an assumption about the war in Iran being short-lived,” Newman said. 
With the Strait of Hormuz still closed as of late May, and energy prices astronomically high, Newman said the market could respond by investing in alternative energy solutions like solar. 
“That security standpoint carries a lot of momentum — there’s more investment going on,” he said. “Even if installations go to the races, I don’t see it getting back to what we saw the past three years.” 
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A study conducted by the University of Texas at El Paso (UTEP) indicates that solar energy infrastructure remains viable in the desert regions of Alamogordo, New Mexico, despite the frequent accumulation of dust from the nearby White Sands gypsum dune field. Researchers monitored photovoltaic panels at the Brackish Groundwater National Desalination Research Facility to determine how particulate matter affects energy production in high-sunlight environments.
The research team analyzed the impact of gypsum-based dust on panel efficiency, noting that while environmental conditions in the region present challenges for maintenance, the area maintains significant potential for solar power generation. The study provides data on how these specific atmospheric conditions influence the performance of solar arrays, offering insights for developers operating in arid, dust-prone climates. By evaluating the relationship between local geological features and energy output, the findings clarify the operational realities of maintaining solar technology in the Tularosa Basin.

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A proposed Willamette Valley solar park is back. Neighbors still oppose it  Oregon Public Broadcasting – OPB
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Indian independent power producer (IPP) Inox Clean Energy, an INOXGFL Group subsidiary, has acquired Vena Energy India’s 6GW renewable energy portfolio, expanding its operating capacity and project pipeline. 
Vena Energy’s portfolio includes around 1GW of operational renewable capacity, 1.7GW of solar and wind projects under advanced development and a further 2.7GW pipeline across solar and wind. The platform also comprises approximately 1.2GWh of battery energy storage systems (BESS) in advanced stages and 1.3GWh in the wider development pipeline.
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Following the acquisition, Inox Clean’s operational and near-operational portfolio will increase to around 4GW, while its development pipeline will exceed 12GW across solar, wind and hybrid projects. 
Devansh Jain, executive director, INOXGFL Group, said, “As INOXGFL Group adopts ‘One Integrated’ strategy, enhancing presence across the renewables value chain, all our group entities supplement each other’s growth. Inox Clean Energy continues to scale its IPP portfolio and targets annual capacity additions of more than 3GW, a significant portion of its annual execution will be executed by Inox Wind and would also translate into massive increase in Inox Green’s portfolio.”   
The deal marks BlackRock-owned Global Infrastructure Partners’ exit from the Indian renewable energy market. The transaction has been valued at approximately INR50 billion (US$585 million).  
The acquired assets are backed by long-term power purchase agreements (PPAs) with offtakers including the Solar Energy Corporation of India (SECI), Gujarat Urja Vikas Nigam Limited (GUVNL), state distribution companies and commercial and industrial (C&I) customers. Vena was advised on the transaction by Morgan Stanley and MUFG.
“Vena portfolio comprises a balanced mix of operational assets, near-term commissioning opportunities and a substantial developmental pipeline, providing both immediate earnings contribution and long-term growth potential,” added Akhil Jindal, Group CFO, INOXGFL Group.   
The transaction marks Inox Clean’s tenth acquisition in the past ten months as the company continues to expand its renewable energy portfolio in India. The company is targeting 10GW of installed IPP capacity and 11GW of integrated solar manufacturing capacity by fiscal year 2028. 
The acquisition is the latest in a series of deals by Inox Clean Energy, which has completed several acquisitions, expanding its renewable energy and solar manufacturing portfolio. 
Last month, the company acquired US solar manufacturer Boviet Solar Technology in a deal valued at approximately US$750 million, gaining access to 3GW of solar module manufacturing capacity in the US. The transaction also included an agreement for a further 3GW of solar cell manufacturing capacity, which is expected to come online by the end of 2026. 
In a separate transaction, Inox acquired Macquarie-owned Vibrant Energy in a INR50 billion (US$535 million) transaction, adding 1,337MW of commercial and industrial renewable energy assets across India.  
Additionally, the company entered the African renewables market earlier this year through a joint venture with RJ Corp, acquiring Skypower Services MENA and targeting an initial portfolio of around 570MW. 
Prior to this, Inox acquired a 300MW operational solar portfolio from SunSource Energy. The assets, spread across 13 Indian states, are backed by long-term PPAs with C&I customers.

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Across the Middle East, countries facing severe energy access challenges are turning to renewables to power essential infrastructure, from hospitals to schools and street lighting.
These include countries coping with, or recovering from, conflict such as Yemen, Lebanon, Iraq and Syria, in a region acutely affected by the high temperatures driven by the climate crisis.
The UN Office for Project Services (UNOPS) is working with partners to provide sustainable energy solutions that support everyday life, create equal opportunities and expand access to essential services.
Read the full multimedia story here.
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Two Lumi robots “talking” to each other during a demo. Image: Luminous
One of the solar-building robot companies operating in Australia could now, theoretically at least, build large chunks of a solar farm from the comfort of their port-side offices – in Boston. 
Luminous Robotics is rolling out “synchronised heterogenous fleet autonomy” – aka software that allows remote control as well as robot-to-robot communication – in the fleet it’s running in Australia. 
The Lumi device picks up solar panels and puts them on the trackers. 
Luminous panel installer robot at the Goorambat solar project. Image: Engie
The company has run Australia Renewable Energy Agency (ARENA) funded trials at two now-completed solar projects and has just finished a third, with another giant project in the wings. 
They aren’t building solar farms remotely, of course, because there are rules around this sort of thing. 
“Our machines are autonomous, however, we do deploy them with safety technicians nearby the robots (similar to early days of autonomous cars) – we do this to adhere to the construction safety guidelines and Job Hazard Analysis defined by each of our construction customers,” Luminous CEO Jay Wong tells Renew Economy over email. 
“We have the capability today to monitor and control these robots anywhere in the world, (i.e. as I write this email today, I can monitor our fleet over in NSW, AU).”
The Boston-based company received grants to trial its “empathy first” Lumi robot technology at the 350 megawatt (MWac) Culcairn solar farm in New South Wales (NSW) and the 250 MW Goorambat East project in Victoria.
Since then, it finished installing panels at the 80 MW Lancaster solar project in Victoria earlier this year as well. 
Wong says they’re working with a “500 MW+” project now, but can’t reveal who it is yet. 
Much like robot vacuum cleaners map out a house and store that away for future reference, so will the Lumi bots for a solar site. 
“What this physically looks like is that the robots within the fleet simultaneously map out the site, building a shared digital twin of the “as built” – every panel installed tagged with before/after imagery and geolocated with GPS locations,” Wong says. 
“The map also contains the geometries and topography of the site, things like trenches, piles, grading, etc.”
Robotics for solar farm construction is being explored by everyone from national science agency CSIRO with its repair bot Bear, Chinese companies Trinasolar and Leapting which have rivals to the Lumi bot, to Built Robotics and Nexttracker have pile driving technology. 
Built Robotics installs piles at the Cloudbreak solar project in the Pilbara. Image: Fortescue
Built is testing its devices on a Fortescue project in the Pilbara, and Nexttracker said last year said it would test a robotic pile driver in Australia. 
Their pitch, and that of solar developers, is that human labourers are scarce and these devices free up that talent for other work. 
Leapting says its pick-and-place robots can do the work for three to four humans. 
But the other element is cost: robots are cheaper and faster than a team of human beings, and can work in very harsh conditions.
ARENA’s stated goal is to bring down the cost of large scale solar to below $20 a megawatt hour (MWh), and see cell efficiency improvements of 30 per cent by 2030.
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Rachel Williamson is a science and business journalist, who focuses on climate change-related health and environmental issues.
Rachel Williamson is a science and business journalist, who focuses on climate change-related health and environmental issues.
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France, Germany, Portugal and Spain all set new records for daily solar production last week, according to the latest analysis from AleaSoft Energy Forecasting.
The Spanish consultancy found Germany generated 503 GWh of solar energy on May 28, the same day France reached 179 GWh. A day later, Spain produced 265 GWh and Portugal 32 GWh.
The milestones represent another record-breaking week for solar production in Europe after France, Germany, Italy and Portugal all set new solar records for a day in May the week prior. Italy broke its record for solar production in May again last week, reaching 161 GWh on May 26.
AleaSoft’s analysis of electricity prices found the weekly average electricity price decreased last week across the Belgian, British, Dutch, German and Nordic markets, which it attributes to higher solar and wind energy production, as well as lower electricity demand.
Despite their daily solar records, France, Portugal and Spain, alongside Italy, saw a week-on-week increase in their average electricity price, which AleaSoft says was caused by a drop in wind energy production and higher demand.
The average electricity price was below €95 ($110.38)/MWh in all analyzed markets except the British and Italian market, which saw averages of €121.97/MWh and €123.58/MWh. The Nordic market registered the lowest average of the week, at €48.37/MWh.
AleaSoft is expecting this week to bring an increase in the average electricity price across most markets, driven by less solar production and higher demand.
The consultancy’s analysis of TTF gas futures in the ICE market found prices reached their lowest settlement of the week on May 25, at €45.43/MWh, before reaching their highest settlement of the week, at €47.47/MWh, the day after.
By the end of the week, TTF gas futures had settled at €46.00/MWh, 5.5% lower than the week prior.
“The conflict in the Middle East continued to influence the trend in TTF gas futures prices during the fourth week of May,” AleaSoft explains. “Expectations of an agreement between the United States and Iran exerted downward pressure on prices, keeping them below €50/MWh. However, low European storage levels and higher demand driven by high temperatures limited further declines.”
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A new solar farm, if approved, would generate approximately 3,000 megawatt hours of energy annually, effectively covering all of the airport’s electrical needs.
A large solar array is being planned to fully power Northeast Philadelphia Airport (PNE).
A bill that still needs approval by City Council would authorize a contractor to build a 1.5-megawatt solar farm. In return, the city would purchase the energy for the airport for 25 years at a set rate.
It would become the largest municipal on-site solar project within city limits. There are larger privately run solar arrays.
The plan is a partnership between the city’s Department of Aviation, which manages both PNE and Philadelphia International Airport, and the Philadelphia Energy Authority.
“The Department of Aviation is committed to purchasing or generating 100% renewable energy through collaboration with the City of Philadelphia Office of Sustainability,” Jessica Noon, sustainability manager for the airports, said at a hearing Tuesday by the council’s Committee on Transportation and Public Utilities.
Noon said Reactivate LLC, a subsidiary of Chicago-based Invenergy, will own the solar array. It will be responsible for construction, daily operations, and long-term maintenance.
Noon said that means the city bears no related costs, other than purchasing the energy, which cannot be sold elsewhere.
She said that will bring stability to the airport’s energy costs for decades, avoiding energy market volatility. She estimates it will result in $116,000 in energy savings over the life of the contract.
A 1.5-megawatt solar system can generate approximately 3,000 megawatt hours of energy annually, or enough electricity to power about 200 homes annually, according to data collected by the Solar Energy Industries Association.
Katie Bartolotta, a vice president at the Philadelphia Energy Authority, an independent city agency, said the project has been years in the making.
She said a previous attempt to build a solar array at the airport was scuttled in 2022 because of issues connecting to the electrical grid through Peco. Those issues have since been resolved, she said.
Officials are pushing for the new array to be built soon in order to take advantage of expiring federal renewable energy credits under President Donald Trump.
The project would provide power for daily airport operations, not planes, which run on aviation-specific fuel. Officials anticipate the solar farm would begin producing energy by Dec. 31, 2027.
Philadelphia is already powering multiple buildings through agreements with solar farms outside the city.
The bill to authorize the agreement was sponsored by Councilmember Brian J. O’Neill and is slated to be introduced in Council on Thursday.
PNE is located on 1,150 acres off Roosevelt Boulevard and Grant Avenue. It is used mostly by pilots flying single- and twin-engine plans, turboprops, helicopters, and jets.
A medical transport jet crashed into Northeast Philadelphia shortly after taking off from the airport in February 2025, killing all six aboard, including a child. The jet slammed into a residential neighborhood, creating a blocks-long disaster, also killing two people on the ground.

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This guest post is by:
Lauri Myllyvirta, lead analyst at the Centre for Research on Energy and Clean Air
China’s carbon dioxide (CO2) emissions grew by 2% in the first quarter of 2026, after a rise in the amount of “wasted” wind and solar power.
The country used more coal and gas to generate electricity than in the same quarter a year earlier, despite a record amount of new wind and solar capacity being built.
While the strait of Hormuz crisis has boosted China’s focus on energy security – including through clean energy and electrification – its electricity system is failing to keep up.
The new analysis for Carbon Brief shows that, while China’s CO2 emissions from fossil fuels and industry increased in the first part of 2026, they remain below the peak in early 2024.
Other key findings for the first quarter of 2026 include:
The key reason for “wasted” wind and solar generation was the inflexible management of coal power plants and power grids, not a lack of grid infrastructure.
In the first quarter of 2026, China’s energy system also began to adjust to the surge in oil and gas prices due to the blockade of the strait of Hormuz.
This continued through April and May, with sharp reductions in oil imports and oil-based chemicals production, as well as the share of gas in electricity generation.
However, the inability to make full use of new wind and solar power plants left China more exposed to the closure of the strait of Hormuz, by increasing the need for other fuels.
This exposure could become more acute if the “super El Niño” that is forecast for later this year limits the electricity output of hydropower, while fossil-fuel supplies remain tight.
Nevertheless, the Hormuz crisis could result in China following a lower-CO2 trajectory than previously expected, if key policies in its 15th five-year plan are fully implemented.
Recent analysis for Carbon Brief showed that China’s CO2 emissions from fossil fuels and industry had been “flat or falling” for nearly two years.
The latest analysis points to a rise of 2% year-on-year in the first quarter of 2026, as shown in the figure below. For now, however, emissions remain below the peak in March 2024.
In previous quarters, emissions had fallen in almost every sector of the economy, with the exception of the coal-based chemicals industry.
The latest quarter saw more widespread increases, with the power sector by far the largest source of emissions growth, as shown in the figure below.
Emissions from other sectors were relatively stable in aggregate, with some rising and others continuing to decline.
Coal consumption in the chemical industry continued strong growth, increasing by 20%, but showed no change in trend after the closure of the strait of Hormuz and surge in oil prices.
(This is contrary to some commentary arguing that the closure of the strait of Hormuz has resulted in a marked increase in the output of China’s coal-chemicals industry.)
The apparent consumption of oil products rebounded in January-February, driven by transportation, but declined slightly in March as oil prices surged.
Emissions from the cement and steel industries continued to fall, as real estate investment contracted another 11% in the first quarter of 2026, following a 17% reduction in 2025. Cement production fell 7% and crude steel output by 5%.
After falling in 2025, power generation from coal and gas increased by 4% in the first quarter of the year.
Power demand grew at 5.2% and hydropower generation increased 9%. Under these circumstances, the record growth in solar and wind power capacity in 2025 should have covered demand growth and pushed fossil-power generation down.
The trend was accentuated in March, as power demand grew just 3.5%, hydropower output increased 9% and yet fossil-power generation increased 4.2%.
The reason for fossil-power generation growth was a sharp drop in the electricity output per unit of installed capacity for both solar and wind power, known as the “capacity factor”.
If capacity factors were stable, the increased solar and wind capacity would have been expected to result in 160 terawatt hours (TWh) of additional clean-power generation during the first quarter, compared with the same time last year, with nuclear and hydro bringing the total to 170TWh. This would have comfortably exceeded the 120TWh increase in power demand.
However, the actual increase in clean-power generation was just 60TWh, with wind showing almost no growth.
While wind power capacity grew by 23% from the first quarter of 2025 to the same period in 2026, an increase of 120GW, the average capacity factor fell from 27% to 22%, a reduction of 18%. This implies that power generation from wind only grew 1% year-on-year. In the case of solar, capacity grew by 33%, but the average capacity factor fell by 11%, resulting in 18% growth in solar-power generation.
It is normal for solar and especially wind capacity factors to vary year-to-year due to weather conditions, but the fall this year was an extension of a longer trend. The average capacity factors of solar and wind have fallen by 19% and 10%, respectively, from 2022 to 2025.
A quarter of the fall in capacity factors over the three-year period is explained by the increase in reported curtailment. This refers to the amount of electricity that is effectively “wasted”, or curtailed, because it cannot be accommodated by the power network.
Nor can the remainder of the fall in capacity factors be explained by the change in weather conditions, as both wind and solar conditions improved on a national-average basis from 2022 to 2025.
In the first quarter of 2026, approximately half of the drop in wind capacity factor and a quarter of the drop in solar capacity factor was explained by weather conditions, implying that the rest is due to increased curtailment resulting from inadequate grid management and integration. 
One clear symptom of increased curtailment is that in January-February, both solar and wind conditions were actually better than last year, but capacity factors still fell.
The fact that capacity factors have fallen significantly more than would be expected based on reported curtailment and weather conditions indicates that a lot of curtailment goes unreported, either because it is excluded from the statistical definition, or because there are gaps in reporting.
Market participants have long noted that actual curtailment is much higher than reported in official statistics.
Official data on curtailment only includes “system reasons”, while excluding some lost generation linked to market trading, grid-connection conditions and other “special” causes.
The figure below shows actual electricity generation from wind and solar plants (dark blue), the amount that would have been generated if reported curtailment had not taken place (light blue) and the level expected if the rate of curtailment had stayed the same (mid-blue).
In total, wind and solar could have generated an extra 170TWh of electricity in the first quarter of 2026, if the rate of curtailment had not gone up in the preceding years. This is more than the total power generation of France over the same period.
The largest reductions in capacity factors, after controlling for variations in weather conditions, came from Inner Mongolia, Xinjiang and Liaoning. In these northern provinces, the heating season is a challenging time for grid managers due to inflexible operation of plants that provide both heat and power.
More broadly, the key reason for curtailment is inflexible grid management. Flexible operation of coal and gas-fired power plants could very substantially increase the amount of solar and wind power the grid can accommodate.
Yet currently, coal-fired power generation is largely operated via medium- and long-term contracts to supply fixed amounts of electricity at fixed prices, meaning there is no incentive for adjustments in output to make space for solar and wind.
Similarly, electricity trading between provinces is predominantly contracted annually, preventing the variable output of solar and wind from being transmitted between jurisdictions in real time.
These issues have a clear impact on the amount of wind and solar that is curtailed. For example, power-system modeling carried out for the year 2023 indicates that flexible power-grid operation would have essentially eliminated the need for curtailment.
The government has also recognised solar and wind curtailment as one of the central challenges of the energy transition.
Recent policies have called for increased inter-province trading and improved flexibility of coal-power plants as the solutions, implicitly recognising these as key issues to address.
Recent large increases in storage capacity, including pumped hydro and batteries, should have improved the integration of wind and solar into the grid. But there is a lack of incentives for storage operators that limits the benefits the system can derive from the technology.
The government has implicitly recognised this and called for establishing electricity pricing that enables energy storage to “participate fairly”.
Meanwhile, China’s new renewable-pricing rules, which shifted existing solar and wind plants to selling electricity on the market, rather than being compensated directly by the grid operator, does not seem to have reduced curtailment so far.
Most provinces only finalised their plans for implementing the policy in late 2025, which left little time for the market and operators to adapt.
China is aiming to build a “new type power system”, capable of integrating large amounts of wind and solar into the grid by 2027. In the meantime, the government has also called for “reasonably pacing” utility-scale “new energy” capacity additions to match the pace at which provinces think they are able to improve the “regulation capacity” of their grids.
China’s energy system has started, since March, to adjust to the surge in oil and gas prices triggered by the closure of the strait of Hormuz. There have been sharp reductions in oil imports, the share of gas in thermal power generation and in oil-based chemical production.
The consumption of gas fell overall in March, even as consumption in the power sector increased. The power sector fuel mix shifted from gas to coal, but the increase in overall thermal power generation still pushed gas use up in the sector.
High gas prices had already been straining household finances before the current crisis. Millions of households were shifted from coal stoves to gas-based heating as a part of efforts to tackle air pollution during the past decade. However, the gas-price subsidies created to enable this shift have expired in recent years, leading to a rise in heating bills.
China’s oil imports started falling sharply immediately after oil prices surged, with net imports falling even further as exports were restricted. The fall has continued into May, with shipments falling by over 40% year-on-year in the first three weeks of the month.
In the first quarter of the year, state-owned oil major Sinopec reported oil product sales up 4.8%. Apparent consumption of oil products had increased 5.5% in January-February, but fell -0.3% in March, indicating an early impact of the price surge, although the late timing of the Chinese New Year also had an effect.
Electric vehicles have continued to gain market share in 2026, reaching 53% of vehicle sales in April, up from 47% a year ago.
Electricity demand for EV charging grew over 50% year-on-year in March. The large number of plug-in hybrid vehicles on the road means that drivers can switch from petrol to power quickly when there is more of an incentive to do so.
Moreover, 24% of highway trips during the 1 May holiday were made by EVs, even though they only make up 15% of all registered cars. This shows that EVs tend to be driven more than average, making a bigger dent in oil use than their share in the fleet would suggest.
Crude oil processing volumes fell by 2% in March and 6% in April, after growth in January-February. Plastics output growth moderated in March and turned into a decline in April.
The increase in oil prices has boosted the profitability of the highly carbon-intensive coal-to-chemicals industry. There has also been speculation that the industry would have forcefully increased output in response to the Hormuz crisis, enabling China to cut back on oil use. The industry was, however, already operating at high capacity utilisation before the current crisis, reported at an average of 87% in the first half of 2025. This means there was little headroom in the sector to raise output in the short term.
Coal use in the chemical industry increased 19% in January-February and 22% in March, showing a rapidly rising trend, but no step change after the start of the crisis.
The global fossil-fuel crisis is also affecting China’s clean-energy industry through overseas demand. Exports of solar, batteries and EVs recorded 56% growth year-on-year in the first quarter, reaching $55bn. This increase was partially driven by front-loading of shipments ahead of changes to tax rebates to solar and battery exports at the end of March, but the value of exports also grew 38% in April, an indication of strong underlying demand.
The oil-and-gas crisis represents an opportunity for both clean energy and coal. The economics of electrification and clean-energy production, as well as of domestic coal production, have improved dramatically as imported fossil fuels have become more expensive.
At least as importantly, the closure of the strait of Hormuz and the resulting global fossil-fuel crisis closely mirror Chinese policymakers’ long-standing concern about reliance on seaborne fossil fuels. This is likely to reinforce their focus on energy security.
The previous fossil-fuel crisis, in 2021-2022, led to a new wave of coal-power plants, coal mines and coal-to-chemicals plants being built in China.
This time around, any expansion in coal mining is expected to be limited, both by the government’s “anti-involution” drive, which aims to stem harmful price competition, as well as by the carbon constraints in China’s climate goals.
Domestic coal production fell in the first four months of the year, despite a rise in oil and gas as well as coal prices. Rising coal prices will reduce the profitability of coal-fired power generation, at least for the next few months.
The perceived need for further new coal-power projects is also limited by the fact that, after record additions in 2025, there was still another 206GW of coal-fired capacity under construction in January, due to large volumes of permitting during the previous five years.
The energy regulator recently called on provinces to “strictly limit” the addition of new coal-power plants and other “regulating” power capacity in areas with sufficient firm capacity.
There is also a ceiling on the upside for coal in the current crisis, because gas plays a limited role in China’s energy system. This leaves little space for replacing gas with coal.
The exception is the coal-to-chemicals industry, which can replace oil and gas, albeit at the cost of very high carbon emissions. As a result, investment in the industry will likely get a further boost, even though the economic incentive is lower than it may seem.
While crude oil prices for delivery this summer have increased by more than $40 per barrel since the start of the year, 2030 prices are only up $5. This is a more relevant benchmark, given that a new coal-to-chemicals plant will take several years to build and commission.
The coal-to-chemicals expansion will also be limited by the new system to control carbon emissions. In particular, the requirement for local governments to compensate for carbon emissions from new industrial projects by closing down existing capacity, if these controls are implemented effectively.
Since the previous fossil-fuel crisis, the concept of energy security has become broader, encompassing clean energy and electrification, rather than being limited to coal and fossil fuels. This shift is also clear from how state media has been covering energy security in the wake of the war on Iran.
As such, the oil-and-gas crunch is likely to speed up the electrification of transportation and buildings. It also strengthens the case for “green fuels”, referring to green hydrogen and synthetic gaseous and liquid fuels produced from it, which are an important priority in the new five-year plan.
Solar and wind also become more attractive, economically and politically, as a result of the crisis. The upside may be limited by the dominant narrative that they have grown faster than the grid can manage, rather than being limited by institutional constraints. Nevertheless, they will benefit from fossil fuels – including coal – becoming more expensive and volatile.
Still, curtailment has become a key issue affecting the pace of China’s energy transition. It both reduces the immediate benefits of clean energy and undermines further investment in clean capacity, by increasing investment risks and cutting into returns.
The flipside of the current rise in curtailment is that when the installed wind, solar and energy storage capacity is put to full use, the supply of clean energy will increase substantially.
As noted, a key priority for the government in the next few years is to build a “new type of power system”, capable of integrating large amounts of variable renewable capacity.
The balance between how much the current crisis benefits coal or clean energy will depend on implementation of key climate and energy provisions in the 15th five-year plan.
If power-system reforms that benefit solar, wind and storage are implemented, while carbon-emission controls limit the expansion of coal-to-chemicals, then China is likely to follow a lower-CO2 emission trajectory than expected before the crisis.
Data for the analysis was compiled from the National Bureau of Statistics of China, National Energy Administration of China, China Electricity Council and China Customs official data releases, as well as from industry data provider WIND Information and from Sinopec, China’s largest oil refiner.
Electricity generation from wind and solar, along with thermal power breakdown by fuel, was calculated by multiplying power generating capacity at the end of each month by monthly utilisation, using data reported by China Electricity Council through Wind Financial Terminal.
Total generation from thermal power and generation from hydropower and nuclear power were taken from National Bureau of Statistics monthly releases.
Monthly utilisation data was not available for biomass, so the annual average of 52% for 2023 was applied. Power-sector coal consumption was estimated based on power generation from coal and the average heat rate of coal-fired power plants during each month, to avoid the issue with official coal consumption numbers affecting recent data. 
CO2 emissions estimates are based on National Bureau of Statistics default calorific values of fuels and emissions factors from China’s latest national greenhouse gas emissions inventory, for the year 2021. The CO2 emissions factor for cement is based on annual estimates up to 2024.
For oil, apparent consumption of transport fuels – diesel, petrol and jet fuel – is taken from Sinopec quarterly results, with monthly disaggregation based on production minus net exports. The consumption of these three fuels is labeled as oil product consumption in transportation, as it is the dominant sector for their use.
Apparent consumption of other oil products is calculated from refinery throughput, with the production of the transport fuels and the net exports of other oil products subtracted.
Estimated non-energy use of fossil fuels is subtracted from total chemical industry fossil fuel consumption, and process emissions are calculated based on fossil fuel consumption with carbon retained in products subtracted. Emissions from the incineration of plastics are based on a peer-reviewed estimate of plastics incineration in 2022, combined with growth rates in the overall power generation from waste-to-energy plants. Metals industry process emissions are calculated using industrial output data and IPCC default emission factors.
Reported curtailment, and capacity utilisation in the absence of reported curtailment, is calculated as the complement of the “offtake rates” (利用率) reported by National New Energy Consumption Monitoring and Early Warning Center monthly by province for solar and wind.
Total curtailment is estimated by comparing solar and wind capacity utilisation predicted based on weather conditions, and in the absence of curtailment, to reported utilisation. Utilisation is predicted by fitting regression models to reported monthly utilisation and weather conditions in 2020-2023.
Weather data used for predicting utilisation are hourly wind speed, temperature, solar irradiation and humidity at solar and wind power plant locations in each province from NASA Power and CFSv2. Locations are taken from Global Energy Monitor data.
Analysis: China’s new carbon metric leaves Germany-sized gap in its emissions
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26.05.26
Guest post: How changes to coal mining have affected China’s methane emissions
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19.03.26
Q&A: What does China’s 15th ‘five-year plan’ mean for climate change?
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06.03.26
Ma Jun: ‘No business interest’ in Chinese coal power due to cheaper renewables 
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19.02.26
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Cardinal News
Serving Southwest and Southside Virginia
Botetourt County, a place so proud of its history that people still talk about how it once stretched all the way to the Mississippi, has met the future — and doesn’t seem to much like it.
Botetourt has now become ground zero for two of the most controversial technological developments in the land these days — data centers and solar farms.
Google is preparing to build a data center in the county’s business park; there have been multiple protests, although there’s likely nothing procedurally that can stop the project. Google has bought the land, and it’s properly zoned. There are some state water permits, but even the Mountain Valley Pipeline secured its permits, so the opposition seems futile — though still passionate.
Now there are proposals for two utility-scale solar farms — “industrial solar” in the language of opponents — before the county’s planning commission. These would be the largest utility-scale solar projects in the Roanoke Valley. Just as data centers are now spreading out of Northern Virginia, solar projects are now expanding out of Southside to west of the Blue Ridge. Unlike the Google data center, there are lots of procedural steps ahead of these projects, starting with a planning commission meeting on Monday.
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I live in Botetourt, so have had a front-row seat to the controversy; the county has now sprouted lots of “No Industrial Solar” signs. I offer no opinion on whether these projects should be approved or denied. What fascinates me are the political contradictions inherent in all these views. We’ve seen these contradictions in other communities, but there’s an old saying in journalism that there’s never a story as important as the one an editor sees happen outside the window. (That’s a joke, by the way.)
Logically, Botetourt County — and other rural counties — ought to be embracing data centers. Botetourt voters cast 71.8% of their ballots for Donald Trump in 2024, and promoting artificial intelligence has been a key Trump policy. It hasn’t gotten the same attention as other policy initiatives, such as immigration and tariffs, but that’s beside the point. Trump has been an enthusiastic supporter of artificial intelligence. Just two days after he returned to office, he issued an executive order that declared establishing American dominance in AI — versus the Chinese — is of “paramount importance.” He announced a $92 billion plan to invest in AI and the energy needed to power it.
There is no artificial intelligence without data centers.
Rural, Trump-voting localities pushing back against data centers is completely understandable — these facilities are thirsty for water and power and often make a lot of noise. Still, on the political level, this is not much different than these counties suddenly breaking with Trump on immigration or tariffs — they are going against a key Trump initiative. Nobody really frames it that way; it’s usually framed as “the people” standing up against “Big Tech.” However, Trump here is on the side of Big Tech, so that’s a distinction without a difference.
What are the long-term political implications of this split between rural counties and the president they backed by overwhelming margins? In theory, this opens an opportunity for Democrats. Nationally, Sen. Bernie Sanders has called for a moratorium on data center development. Closer to home, so has Beth Macy, the Democratic candidate for the 6^th District seat in the U.S. House. More practically, though, since AI isn’t as branded as a Trump initiative as immigration and tariffs are, many people probably don’t see the connection — and in the end, rural voters may be more moved at the ballot box by all the other issues that traditionally led them to Republicans. We’ll see.
Property rights has historically been a key conservative value. Some rural counties in Virginia are still so respectful of property rights that they have no zoning ordinances. If we were ideologically consistent (and we rarely are), rural localities ought to embrace — or at least tolerate — solar projects as a property-rights issue.
That’s rarely the case, though. It’s certainly not in Botetourt, where the rallying cry against solar has been “Keep Botetourt Green.” That’s essentially a rejection of property rights and an assertion of a liberal view that we have a right to tell our neighbors what they can and cannot do with their land — that we have a community right to look onto our neighbors’ land and see green fields, not shiny black solar panels. Before you fire off your angry emails, keep in mind that I live in a rural county because I, too, like to see green fields; I’m just pointing out the ideological inconsistency we have. When it comes to solar, some otherwise independent-minded, small-government rural residents want to adopt the same mindset as a homeowners association.
I went looking for the two proposed solar sites in Botetourt County. The biggest of them — a 53.40-acre parcel — is on the main road, U.S. 220, between Daleville and Fincastle. For those not familiar with Botetourt, that’s smack in the middle of the county’s growth sector. This land is green now but is unlikely to stay that way, whether there’s a solar project built there or not. Before I found it, I came across a neighboring tract with a site that advertised: “Land for sale — 30 acres.” That’s a subdivision waiting to happen.
When I did find the 53.40 acres, what I saw was mostly a steep hillside, with the rest of the property impossible to see from the main road. I don’t know what neighbors further back might see, but those driving by would see nothing. The county’s GIS map shows that most of the property is set back from the road.
The smaller tract, a 20.69-acre parcel on Catawba Road, is behind a row of five houses and does not appear to be obviously visible from the road. This property might be more classically rural, but that stretch of Catawba Road has lots of houses, and there is active home construction underway on at least one parcel.
In both cases, if this land isn’t used for solar, it seems destined to be developed for homes. 
I grew up on a farm; a 20-acre parcel isn’t really farmland; it’s a field. This isn’t a case of prime agricultural land being taken out of production because any production here would be slight. In some places, some farmers would argue that solar isn’t industrial at all; it’s a way to make their farms more profitable, and that some livestock (such as sheep, but occasionally cows) are quite happy grazing under solar panels.
The choice here isn’t really between solar and staying green forever, as much as we might wish it would stay that way; it’s between solar and whatever else might become of that land, be it a subdivision or commercial development. Solar might still lose out in that equation, but unless someone wants to put some kind of easement on that land, it will get developed for something at some point. Governing is about choices, and that’s one of the choices to be made here. What should the landowner be allowed to do with their land? Is solar better or worse than a subdivision?
We have two things going on here at the same time. The Virginia Clean Economy Act requires the state’s two biggest utilities (Dominion Energy and Appalachian Power) to convert to noncarbon forms of energy (solar, wind, nuclear) with some exceptions for certain circumstances for natural gas. For Appalachian, the utility that serves much of Botetourt County, the deadline for conversion is 2050. That act has driven the explosion of solar farms across rural Virginia, particularly Southside. Because of that law, this would be happening even if there were no data centers — so we can’t connect these solar projects in Botetourt with data centers, but we can tie them back to the Clean Economy Act. Virtually every Republican legislator at the time voted against that law, and Republicans still think it should be repealed or drastically revised. Politically speaking, rural representatives in Richmond opposed this forced transition to renewables, yet the consequences of this law have mostly played out in their districts.
The Clean Economy Act was passed before the impact of data centers hit in a big way; energy demands, which were generally steady before then, have now spiked. The result is that Virginia now imports a lot of energy (only California imports more), and that energy tends to be both dirty (carbon-intensive) and expensive. Even if you’re not concerned about carbon emissions, you’re probably concerned about your monthly bill, so here’s an issue where left and right are in tenuous alignment: They both agree we need more energy.
Now, here’s what neither side likes to say very loudly, or at all: The reality is that most of that energy is going to be produced in rural areas because that’s where the land is — and where there are fewer people to object. Every now and then, you’ll see a proposal for a metro area — such as Dominion Energy’s proposal for a natural gas plant in suburban Chesterfield County — but that’s more an exception than the rule.
(Disclosure: Dominion is one of our donors, but donors have no say in news decisions; see our policy. You can be a donor, too, and also have no say.)
The left generally prefers renewables, which in Virginia overwhelmingly means solar. Solar needs land, and that means the energy preferred by Democrats winds up mostly in Republican-voting areas. That’s created political tension in Richmond. The legislators who most want solar don’t have to live with the consequences. Those who do want it the least. My impression is that Democrats don’t fully appreciate the depth of the anger about solar that we sometimes see in rural areas. If they want to see that anger first-hand, I invite them to come to Botetourt, and I’ll show them around.
We’re now seeing legislation — from state Sen. Schuyler VanValkenburg, D-Henrico County — to encourage more solar development in metro areas. What we don’t know, because it’s too soon to tell, is what the market will think. There are often those who ask why we don’t put solar panels over top of parking lots (I’ve been among those who have asked that). I see that’s one of the suggestions from the group Keep Botetourt Green. The catch is that solar developers have told me that parking lot solar is expensive — you have to build the infrastructure to hold it up — and that cuts into the profit margin too much. They basically weren’t very interested. Legislators could mandate parking lot solar, if they chose, but they’d be voting for a more expensive form of energy. That probably would not look very good on an opponent’s literature in the next campaign.
The right generally prefers natural gas, but we just saw how difficult it was for the developers of the Mountain Valley Pipeline to build their route through rural areas. Trump likes to say “drill, baby, drill,” and crowds cheer, but he doesn’t talk about “build pipelines, baby, build pipelines,” which is the inevitable next step. Most of those pipelines would go through communities that voted for him and other Republicans. 
There’s also another market reality: speed to market.
You may have seen the cheeky signs in some businesses: “If you want it done cheap and fast, it won’t be good. If you want it done good and fast, it won’t be cheap.” That definitely applies to energy. We’re seeing lots of solar development because it’s the quickest form of energy to get up and running. A developer can build a solar farm before the paperwork for anything else is even complete. The problem is that solar is very inefficient. Solar farms don’t produce power at night, and they don’t produce full power on cloudy days. The efficiency of solar projects is generally put at about 20% or so. That means we wind up devoting a lot of land to an inefficient form of energy because it’s cheap and quick. One reason it’s cheap is because the fuel source, the sun, is absolutely free. The most land-efficient form of energy is nuclear, but it’s slow and expensive. We also don’t see many communities that want a nuclear plant (or even a gas plant or, in Botetourt, a solar farm) next door. We, as a society, need to decide which we want. That brings us to this:
Botetourt County is served by two different utilities: Appalachian Power and the Craig-Botetourt Electric Cooperative. The State Corporation Commission provides a list that shows the Craig-Botetort co-op has the highest monthly power bills in the state, at $197.40 per kilowatt for an average monthly bill. Appalachian was about in the middle of Virginia utilities, at $163.56, when the SCC chart was compiled. It’s now a few dollars higher. Dominion, the state’s biggest utility, is at $170.61.
Nobody likes their power bill, no matter which utility we’re served by. We all want cheaper power. Logically, Botetourt residents (at least those in Craig-Botetourt territory) should want it more than anybody else in the state. Here we have two of our county neighbors who are willing to lease their land to an energy developer to produce cheaper energy — but now some don’t want that because they think it’s unsightly and out of character with the county. This is the essential conundrum we face with any energy development: Nobody wants it near them, no matter what it is. That’s completely understandable; those of us who live in rural areas generally live there because we don’t want much of anything around us. However, if we don’t want energy produced here, that means it will get produced somewhere else, which means there will be transmission lines — and they’re never popular, either, as we see from the current controversy over the Valley Link project, a proposed extra-high-voltage transmission line planned to run 115 miles from Campbell County to Culpeper County. If you’re starting to think there are no good choices, you’re right. There’s a problem here with everything.
None of this will help Botetourt County planners make a decision, and none of this will assuage those Botetourt residents who feel strongly about “industrial solar,” or those who worry that we’re about to bake the planet and we need to do whatever we can to stop carbon emissions. But it does put what’s happening in context, however uncomfortable that context may be for everyone.
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Yancey is founding editor of Cardinal News. His opinions are his own. You can reach him at dwayne@cardinalnews.org… More by Dwayne Yancey
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Avangrid, a United States-based energy firm, has completed construction of the 166 MW (DC) (120 MWac) Tower Solar project in Morrow County, Oregon. The company has also connected the solar facility to the regional electricity grid and also project uses more than 250,000 solar panels assembled by SEG Solar in Houston, Texas. The commercial operation is expected during summer 2026 following final commissioning activities. Electricity generated by the facility will be supplied to Portland General Electric and support QTS operations in the region. Located on approximately 900 acres near Boardman, the project created around 200 construction jobs, primarily filled by union labor. Tower Solar is also expected to contribute about $20 million through PILOT and property tax payments to local communities.

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Since 2019, the intraday structure of the GB power market has changed materially. Midday gas generation has fallen sharply, while three north-west European interconnectors now import into Britain during solar hours before reversing direction overnight. The result is a persistent £22 ($29.5)/MWh spread between midday and evening power prices that current interconnector flow patterns do not fully arbitrage.
For most of the past two decades, gas-fired generation acted as the balancing fuel of Britain’s power system. Combined-cycle gas turbines ramped through the day and eased back overnight when demand was lowest. Between 2019 and 2025, UK gas generation fell by a third and coal generation disappeared entirely. Wind and solar now generate more electricity than gas. Midday has become the cheapest period of the trading day and the most likely to clear at negative prices, while evening prices continue to reflect thermal generation costs roughly £22/MWh higher. Britain has become a daytime sink for surplus continental solar, importing power through north-west European interconnectors during daylight hours and exporting wind-driven surplus back overnight. Britain’s wind fleet supplies the discharge half of that cycle. The combination is reshaping wholesale price formation in Britain and recalibrating the economics of assets that must clear in the market.
Between 2019 and 2025, the UK generation mix changed materially. Gas generation fell 33%, from 115 to 77 TWh. Coal generation fell from 5.9 TWh to zero following the closure of the UK’s last coal station in September 2024. Nuclear generation fell 35% to 34 TWh as AGR retirements accelerated. Over the same period, wind generation increased 47% to 86 TWh, solar generation rose 62% to 18.7 TWh, and net imports across the eight measurable interconnectors more than doubled to 22 TWh. Total generation remained broadly stable, falling only from 292 to 289 TWh.
At 50% LHV CCGT efficiency, the 37 TWh reduction in gas-fired generation represents approximately 7.1 bcm of natural gas displaced from the UK power sector. With underlying electricity demand broadly flat across the period, the reduction reflects supply-side substitution rather than demand contraction. The CCGT fleet has also shifted away from baseload operation toward deeper intraday cycling. Capacity factors across the UK’s 30 GW CCGT fleet fell from 44% to 29%. Half-hourly minimum gas burn declined from 2.5 GW in 2019 to 1.2 GW in 2025, with the first sub-1 GW half-hours appearing in 2024. Half-hours with less than 3 GW of gas generation increased from 46 in 2019 to 2,349 in 2025, equivalent to 13% of settlement periods.
January to April 2026: The trend has accelerated
Gas generation in January to April 2026 fell to 26.2 TWh, down 20% year on year and only 0.5 TWh above the January-to-April low recorded in 2024. Wind generation increased 34% to 36 TWh, with instantaneous output reaching a record 23.88 GW on 25 March 2026. Solar output peaked at 16.3 GW on 23 April. Whilst it may appear that the market is swinging in wind and solar’s favour, there was a clear increase in negative priced periods – meaning zero payouts from the Contracts for Differences (CfDs) that support many wind and solar projects.  Negative day-ahead prices occurred in 16.9% of midday half-hours during April, up from 11.3% in summer 2025 and 7.7% in summer 2024.
02. Two operating regimes across the GB interconnector fleet
Aggregate net-flow figures obscure two distinct operating regimes across the GB interconnector fleet that only become visible at half-hourly resolution. Three cables operate as quasi-baseload importers, with two primarily carrying French nuclear-linked flows and the third reflecting Norwegian hydro dispatch under current market conditions. Three others cycle several gigawatts within the day, importing during continental solar hours and exporting overnight. Two additional cables operate as a relatively steady westward flow into Ireland. The resulting flow patterns correspond closely to the underlying supply structures of neighbouring power markets.
French interconnectors: structurally importing
IFA2 (1 GW) and ElecLink (1 GW) flowed into GB in 86% of summer 2025 half-hours, with annual churn ratios of 0.05 and 0.02 respectively. The churn ratio measures how often a cable reverses direction, with values near zero indicating near-unidirectional flow. Together the two cables delivered 11.6 TWh of net imports into GB in 2025. IFA1, the original 2 GW France interconnector, returned to full capacity in 2024. Although absent from the half-hourly dataset used here, residual import volumes suggest it also carried substantial inflows.
The flow profile reflects a structural change in French reactor dispatch. Hourly ENTSO-E data show EDF flexing its nuclear fleet by roughly 4.4 GW between midday and evening during summer 2025, compared with limited intraday modulation in 2019. The remaining  midday surplus  is exported into neighbouring markets, with some volume reaching GB directly through the French interconnectors and the remainder lowering continental prices coupled into the GB market. France remained a net exporter in 98.5% of hours during 2025, with total net exports of 92.3 TWh. The export profile is increasingly concentrated outside the continental midday solar peak.
Norway Link: hydro dispatch under current price conditions
NSL (1.4 GW) connects GB to the Norwegian hydro system. The cable flowed into GB in 86% of summer 2025 half-hours, with a churn ratio of 0.05 and annual net imports of 9 TWh. On annual metrics the cable resembles the French interconnectors, but the underlying dispatch logic differs. Norwegian hydro output is optimised against reservoir constraints and cross-border price spreads. Under current market conditions, GB prices continue to support southbound flows during most hours of the day. NSL already exhibits a modest intraday profile, with average flow rising from 783 MW at 14:00 to 1,184 MW around 20:00. The shape reflects the underlying optimisation incentives within the Norwegian hydro system.
Early 2026 data suggest this pattern is beginning to change. Between January and April 2026, NSL registered five aggregate export hours, with the deepest occurring at 04:00 and averaging −156 MW. This is the first quarter on record in which the Norway interconnector has shown aggregate export hours. The underlying mechanism mirrors developments already visible elsewhere in continental Europe. As midday price floors weaken further across Iberia and Benelux, the opportunity cost of holding reservoir water through GB solar hours increases, gradually changing dispatch incentives. If this pattern strengthens, NSL is likely to join the broader intraday cycling behaviour already visible on the continental-facing cables. In that scenario, the effective GB midday absorption ceiling would rise from roughly 3.4 GW across BritNed, Nemo and Viking to approximately 4.8 GW including NSL.
The cycling group: continental solar overflow
BritNed (1 GW), Nemo (1 GW) and Viking (1.4 GW) exhibit a markedly different intraday flow profile. During summer 2025, their combined hourly mean flow ranged from −1,469 MW at 05:00 to +2,135 MW at 10:00, representing an intraday swing of roughly 3.6 GW. Each cable flowed into GB during 79% to 92% of noon half-hours and exported from GB during 64% to 87% of pre-dawn half-hours. BritNed alone recorded 2.9 TWh of gross imports and 2.5 TWh of gross exports during 2025. The flow pattern is driven by continental supply conditions, with German solar generation sitting upstream of all three interconnectors.
Germany has no direct interconnection with GB, so excess midday solar generation first moves into neighbouring continental markets. As flows saturate the France-Germany corridor, the French nuclear fleet increases intraday modulation to absorb part of the surplus. Additional excess generation then spreads north through the Netherlands, Belgium and Denmark before reaching GB through BritNed, Nemo and Viking. The three cables therefore reverse direction within the day, importing continental solar-linked surplus during daylight hours and exporting GB wind-linked surplus overnight.
Ireland and the discharge half of the cycle
Moyle (0.5 GW, Northern Ireland) and East-West (0.5 GW, Ireland) operate as persistent net exporters from GB into the Irish market, delivering 3.9 TWh westward during 2025. The all-island Irish system remains heavily wind exposed and uses GB as a balancing sink during low-demand periods. The largest exports occur overnight when GB wind output is strongest and Irish demand is weakest. Combined with the overnight reversal of the cycling interconnectors, these flows return power to neighbouring markets during periods of elevated GB wind generation. Between 22:00 and 06:00 the cycling cables collectively export from GB, reaching roughly −1,469 MW around 05:00. At that hour, GB wind generation contributes approximately 7.4 GW, equivalent to 33% of transmission system demand. These overnight reversals complete the daily import-export cycle created by continental solar inflows during the day and GB wind surplus overnight.
03. Midday compression and interconnector spreads
GB wholesale prices now exhibit pronounced intraday compression around midday solar hours. Summer baseload prices rose from £19/MWh in 2019 to £36.50/MWh in 2025 following the 2022 gas shock, but the more significant structural change has occurred within the trading day. In summer 2019, midday and evening prices were broadly aligned, with CCGTs setting marginal prices through most hours. By summer 2025, the spread between midday and evening prices had widened to roughly £22/MWh. Midday prices averaged near £28/MWh, while evening prices continued to reflect thermal generation costs closer to £50/MWh. Negative midday prices, largely absent before 2020, occurred in 11.3% of summer midday half-hours during 2025 and in 16.9% of midday half-hours during April 2026. The April monthly low reached −£29.27/MWh.
The resulting capture-rate compression is most visible in solar generation. UK wind capture rates declined from 96% of baseload prices in 2019 to 90% in 2025, while solar capture rates fell from 97% to 83% over the same period. The compression is structural rather than cyclical. Solar generation remains concentrated in the same hours in which prices now clear lowest and increasingly below zero. Projects bidding into the AR8 CfD auction in summer 2026 will need to seriously consider the risk of sustained exposure to negative priced periods in their bids. 
The cycling interconnectors are arbitraging a different intraday spread. The cables reverse direction around dawn, approximately twelve hours before the GB evening peak. Combined flows shift from peak imports of 2,135 MW at 10:00 to peak exports of 1,469 MW at 05:00. During 2025, the volume-weighted GB price associated with imports across the cycling trio averaged £41.69/MWh, while the export-weighted GB price averaged £38.54/MWh. On the GB side, the cables therefore captured a slightly negative average spread. The wider £22/MWh midday-to-evening spread sits largely outside the hours in which the cables reverse direction. In practice, the interconnectors are arbitraging GB midday prices against the continental pre-dawn ramp rather than the GB evening peak. The deeper intraday spread driving solar capture-rate compression therefore remains largely uncaptured within the GB market.
CCGT operators face the same structural shift from the opposite side of the curve. A 29% capacity factor across a 30 GW fleet implies that energy-market revenues no longer dominate fleet economics. Capacity Market revenues and balancing services are becoming increasingly central to asset viability, raising questions around the economics of hydrogen-ready conversion relative to staged retirement against a rapidly expanding BESS pipeline.
Interconnector saturation and the battery response
The next phase of market evolution is likely to be driven by the same intraday dynamics already visible today. Continued solar expansion across Iberia and Benelux is expected to place further downward pressure on continental midday prices, increasing the incentive for additional imports into GB through the cycling interconnectors and deepening midday price compression within the GB market. Early 2026 data already show NSL beginning to register aggregate export hours. If this behaviour becomes established, the effective GB midday import absorption ceiling would increase from roughly 3.4 GW to approximately 4.8 GW. Under current market conditions, this would temporarily expand the system’s ability to absorb additional continental midday surplus.
Beyond that point, two countervailing pressures begin to emerge. First, continued solar growth across continental Europe is likely to increase intraday nuclear modulation within France, reducing the volume of exportable midday surplus available to neighbouring systems. Second, NESO Future Energy Scenarios project sustained GB electricity-demand growth associated with electrification, firming GB midday prices and narrowing the spread that currently draws low-cost imports into the GB market.
Current regulatory structures were designed around a different interconnector flow profile. Ofgem’s cap-and-floor framework continues to assess projects largely around directional merchant flows, while current cable revenues increasingly depend on intraday spread capture. Similarly, NESO trading-cap structures were developed for a system dominated by persistent one-way flows rather than repeated intraday reversals.
In both scenarios, the market signal points toward the same outcome: additional intraday storage capacity within GB. The £22/MWh spread between midday and evening prices strongly favours assets capable of charging during solar hours and discharging into the evening peak within the same market. The spread persists because the relevant arbitrage window occurs largely outside the hours in which the cycling interconnectors reverse direction. At current spreads, a 1 GW four-hour battery cycling once per day captures gross arbitrage revenues of roughly £32 million per gigawatt-year before Capacity Market or balancing-service revenues.
The 23 GW to 27 GW battery target set in the Government’s Clean Power 2030 Plan reenforces the market’s signals that additional storage is required. However, as additional storage capacity enters the market, it is likely to compress the midday-to-evening spread and replace part of the balancing role currently performed through cross-border cycling.  WSP’s Electricity Market Outlook projections suggest declining TB1-4 spreads and lower operating hours for storage over the 2030s as storage cannibalizes its arbitrage opportunities.  
How WSP’s Electricity Market Outlook can help
How quickly will continued continental solar expansion push the GB cycling interconnectors toward their effective absorption limit? At what point does additional GB BESS deployment begin to materially compress the midday-to-evening spread currently visible in the GB market? These questions are increasingly central to CfD bid strategy, interconnector economics and storage investment decisions.
WSP’s Electricity Market Outlook (EMO) is designed to analyse these market dynamics. The underlying PRIMES model has supported European Commission energy-policy analysis for more than two decades and simulates all major European electricity markets simultaneously through to 2050. Cross-border flows are derived using a replication of the EUPHEMIA market-coupling algorithm used by ENTSO-E. Model outputs include hourly wholesale prices, capture rates, negative-price frequency and depth, curtailment exposure, interconnector utilisation and BESS profitability projections at both country and asset level. These outputs provide the quantitative basis for CfD bid assessment, Window 3 interconnector business-case analysis and long-term storage revenue modelling.
Author: Safa Sen, Market Engagement Lead For CWE at Ricardo, Member of WSP.
Ricardo is a member of professional service firm WSP Group, uniting engineering, advisory and science-based expertise to shape communities to advance humanity. ​ ​From local beginnings to a globe-spanning presence today, it operates in over 50 countries and provides solutions and delivers innovative projects across sectors: Transport & Infrastructure, Property & Buildings, Earth & Environment, Water, Power & Energy and Mining & Metals.

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Topic:Solar Energy
Sat 7 Dec 2024 at 6:17am
Rooftop solar can at times meet more than half of the total demand across the national electricity market. (ABC News: Glyn Jones)
If you're one of the 4 million Australian householders or business owners with solar panels on your roof, you may have been greeted with a rude shock at the start of this week.
News emerged that the body responsible for keeping the lights on in Australia's main electricity grids wanted powers in every state to ensure rooftop solar could be turned down — or switched off — in extreme circumstances.
The Australian Energy Market Operator said an "emergency backstop mechanism" was urgently needed everywhere and by next year, no less.
It's a radical notion and not one that's likely to be immediately welcomed by too many rooftop solar owners.
But what exactly is involved in this proposal?
And why on earth is anyone suggesting the powers are needed at all?
The answers to these questions, and more, speak as much as anything to the profound changes underway in Australia's electricity system and the role of householders within it.
As the name suggests, the backstop power would be for emergencies.
More precisely, those circumstances would arise when there is so much rooftop solar in the system that it's threatening to overload the grid.
It's hard to appreciate just how much rooftop solar can be generated at times in Australia.
A couple of decades ago, there was practically none anywhere in the country.
Even when state governments lavished subsidy schemes on solar and people started to take up the technology with gusto, the amount of power that could be collectively generated was tiny.
But fast forward to now and it's a very different story.
Across the entire national electricity market, which spans the eastern seaboard and South Australia and services about 10 million customers, excess solar power exported to the grid from household systems can meet more than half of demand at times.
And in South Australia, arguably the world's rooftop solar capital, that share periodically exceeds 100 per cent.
In other words, South Australia can meet all of its demand for electricity from rooftop solar at times. And what it can't use gets exported interstate.
But with all that solar comes risks for the grid.
Solar power doesn't help keep the grid stable during power losses. The grid needs inertia, which is like the momentum that keeps a car moving smoothly even when you take your foot off the accelerator.
Coal, gas, and hydro plants provide this inertia through their turbines, helping keep the grid steady and maintaining consistent power levels.
Rooftop solar can't do the same thing, and it's increasingly pushing those plants out of the system in the middle of the day when its output is greatest.
Conventional generators can turn down their output to accommodate solar, but only to a point. Eventually, their output becomes so low they have to switch off altogether.
And, for AEMO, that's a worry.
The agency fears the amount of conventional generation providing those security and stability services — and able to step in when the sun stops shining, for example — is falling to critically low levels.
Hence it says powers are needed to "reduce" some of that excess rooftop solar at certain times.
The powers already exist in South Australia, Western Australia, parts of Queensland and Victoria, but AEMO wants them extended everywhere.
It's not entirely clear how emergency backstop powers will work, but AEMO says they are most likely to occur in spring — when the days grow longer and sunnier and solar output soars while demand for electricity remains relatively subdued thanks to milder temperatures.
In those conditions, the agency says the amount of rooftop solar in the system can become a risk if anything goes wrong, such as the unplanned loss of a coal-fired generator or transmission line.
And things always go wrong.
At such a time, AEMO would tell the relevant state or states as well as the network poles-and-wires companies there was a problem.
It would then be up to the states and the poles-and-wires companies to deal with the problem.
One of the levers at their disposal would be the backstop provisions, which would allow rooftop solar systems to be throttled back to stop sending excess energy to the grid, or switched off entirely.
AEMO says it would be up to states and network providers to use the emergency powers. (ABC News: Chris Gillette)
On those occasions, Queensland poles-and-wires companies Ergon and Energex say, affected households can expect a few things.
A signal will be sent to their solar inverter, shutting down generation.
The affected household would then have to take their power from the grid, from which they'd be charged "as per your electricity tariff".
Once the emergency backstop has been removed, "a signal will be sent to the inverter which will return it to normal operation".
All up, according to Ergon and Energex, an emergency would last no more than 4 hours.
What's more, the firms said, "the chances of an 'emergency event' occurring is very low and it may only occur once per year or less".
Added to this, AEMO notes that even in South Australia, where the emergency backstop has been in place since 2020, "compliance rates were initially poor".
Many older, and even some new, solar installations do not have the ability to be remotely switched off.
Rectifying this, AEMO says, is likely to be a long and difficult task.
According to AEMO, the backstop would only ever be wheeled out when all other measures to keep the system on an even keel were "exhausted".
Broadly, those measures would include further lowering — where possible — the "minimum safe operating levels" of the big coal plants that act as bookends for the system.
Doing so would make more room for solar.
Similarly, AEMO says investments could be made in special pieces of kit known as synchronous condensers, which replicate the system strength functions of coal plants without producing any electricity.
Coal plants have long provided intrinsic strength to Australia's grid. How to replace those properties is one of the big challenges in the energy transition.
Another option is to increase demand for electricity during the day, when solar energy is so abundant and cheap.
This could be done by developing industries that need a lot of power but not all the time.
Or it could be through electrification — getting our cars and our household appliances to soak up as much of that solar as possible.
Then there is storage — building more batteries and pumped hydro projects to stash the energy when it's flooding on the grid.
But even with all those options, AEMO says emergency backstop powers will still be needed as a "last resort".
It warned that without such powers, more draconian measures might be needed.
These could include increasing the voltage levels in parts of the poles-and-wires network to "deliberately" trip or curtail small-scale solar in some areas.
An even more dramatic step would be to "shed" or dump parts of the poles-and-wires network feeding big amounts of excess solar into the grid.
On this question, there is some confusion.
Despite vociferously advocating for greater control of rooftop solar and, specifically, the emergency backstop capability, AEMO is at pains to point out it would not be pulling the trigger.
In response to the ABC's reporting of the topic this week, AEMO released a statement in which it said it "does not want to directly control people's rooftop solar".
More bluntly, the market operator stressed there was no "big red button" that allowed it to dump people's solar installations from the grid.
What we do know is that in areas where the backstop exits, households getting new or replacement solar panels will need to have a special type of inverter connecting their system to the grid.
Households installing new or replacement solar panels will need to have a special type of inverter connecting their system to the grid. (ABC: Glyn Jones)
The inverter will have to be capable of receiving a signal to turn off — or down — when required.
And, indeed, it is the poles-and-wires companies that would send the signal to that inverter.
But, according to Ergon and Energex, network firms like them would not be acting alone.
They would be acting "under the direction of AEMO" and "in alignment with" the state government.
Suffice to say, AEMO is ultimately the body responsible for keeping the lights on across the major electricity systems in Australia.
The agency monitors the balance between supply and demand for power and the stability of the grid.
None of this is likely to happen without AEMO first setting the parameters by which the backstop would be used.
In all likelihood, the backstop power will have a minimal effect on solar households.
It may even have no effect at all.
Although rooftop solar is a growing force in Australia's electricity system, the circumstances in which it pushes the grid to the precipice are still rare.
What's more, they only last for a few hours at a time.
Economists love them. Regulators say they make the grid more efficient. But many Australians are finding out time-of-use tariffs mean sharply higher power prices.
To deal with the challenge, AEMO has pointed out all the ways that excess supply can be turned into an asset rather than a liability for the system.
The politicians, regulators and energy experts want us all to use more power when the system is awash with cheap solar and less of it later in the day, when it isn't.
It's why so much effort is being put into installing smart meters on every home by 2030 and introducing surge prices that charge energy customers higher prices in the evening.
Chances are, Australia will learn to better capitalise on its solar riches, avoiding the need to take drastic steps like throttling rooftop solar.
Still, AEMO says the amount of extra solar getting added to the grid every year means the risks aren't going away.
The estimates vary, but rooftop solar generally tends to lower power costs.
A rule of thumb, according to industry players, is that a typical rooftop solar installation will cut electricity bills by about 30 per cent a year.
But how much rooftop solar might save a householder depends on how they use the power generated by the panels.
Generous feed-in-tariffs — the payments made to customers for the excess solar power they export to the grid — are increasingly a thing of the past.
Like millions of Australians, Doreen Fawcett is grappling with a nightmare of unwanted power bill complexity. Calls for simplification are growing.
Whereas once a householder might have received anything up to 60 cents per kilowatt-hour for their solar exports, they can now realistically expect something more like 5 cents.
For that reason, experts say it's now far more valuable to use the power generated by solar panels in your own home rather than sell it to the grid.
After all, buying power from the grid on a flat rate can easily exceed 30 cents a kilowatt-hour — or even double during the peak under surge pricing plans.
Using a kilowatt-hour of electricity generated by your solar panels, on the other hand, costs nothing once the up-front cost is paid.
The spread of emergency backstop powers to be used on rare occasions seems unlikely to change the basic equation in favour of solar.
Sat 7 Dec 2024 at 6:17am
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A Vermont town said yes to wind turbines years ago, but now one solar farm is turning neighbors against each other  Energies Media
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