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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.
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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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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.
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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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Battery energy storage specialist ELM MicroGrid has spent more than two decades building a nationwide energy storage and utility infrastructure businesses. Now, the company is bringing that expertise home with the installation of a new battery energy storage system at a solar microgrid project in Peoria, IL.
Part of the 2.5-megawatt Peoria Solar Energy Center that broke ground last year, the ELM MicroGrid batteries will help the new Peoria microgrid project produce and manage enough electricity to power more than 400 homes and businesses, provide an economic boost to the region.
“At a time when the demand for electricity is outpacing supply in Downstate Illinois, more energy needs to be generated and connected to the grid faster to provide reliability and cost saving benefits for our customers,” said Lenny Singh, Chairman and President of Ameren Illinois, at the project’s launch. “Thanks to a provision in the state’s Climate and Equitable Jobs Act, the Peoria Solar Energy Center – alongside our two other solar facilities in East St. Louis – will produce clean, reliable, and equitable energy in the community, for the community.”
The project sits on a 37-acre site on Prichard Road in northwest Peoria, and features nearly 5,000 solar panels feeding clean power into Ameren Illinois’ distribution system. Excess solar generation can, instead of being curtailed uselessly, be stored usefully in the big ELM battery system to be discharged later, helping reduce stress on the grid during periods of high demand and improving the utilization rate of Ameren’s of locally generated renewable energy.
The Peoria Solar Energy Center is a continuation of Ameren Illinois’ commitment to powering a stronger regional economy. The company has invested $112.4 million in recent years to improve reliability in the Peoria area, including high voltage transmission infrastructure, new substations, and automation to detect outages and restore power faster.
SOURCES: ELM MicroGrid, via LinkedIn; Ameren.
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Scientific Reports volume 15, Article number: 42568 (2025) Cite this article
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Worsening power quality driven by non-linear and converter dominated loads poses a significant challenge in renewable integrated microgrids. This paper develops and evaluates a coordinated source-filter control framework that (i) determines the optimal pairing of sources (PV, BESS, or grid) with either a Shunt Active Power Filter (SAPF) or a hybrid filter (SAPF + passive LC) employing load current based inverter referencing, and (ii) optimizes power quality via hourly selection of the lowest THD source. The study models a 100 kW three-phase grid-tied solar PV array, a 60 kWh BESS (bi-directional DC-DC interfaced), a three-phase H-bridge inverter, utility grid connection, and PQ devices (SAPF and hybrid filter). Linear (10–60 kW) and non-linear (0–50 kW) loads are applied across four modes: grid-tied PV (no BESS), grid-tied PV + BESS charging, BESS discharge (islanded), and grid only supply. An hourly Genetic Algorithm first selects the lowest THD source without filtering, then escalates only non-compliant hours to SAPF or hybrid filtering, ensuring IEEE 519–2014 THD compliance with minimal intervention. Results show BESS + SAPF maintains sub 5% THD even under heavy non-linear loads; PV requires SAPF + load-current referencing at moderate distortion levels; and the grid under ≥ 50% non-linear loading demands hybrid filtering to reduce THD from over 24% to below 3%. This optimization framework secures full hourly THD compliance, enhances microgrid power quality, and supports reliable renewable integration, thus advancing UN SDG-7.
Among the numerous challenges confronting humanity in the twenty–first century, climate change stands out as one of the most significant. Rising global temperatures, more frequent extreme weather events, and shifting ecosystems are direct consequences of increasing emissions of heat-trapping gases, largely driven by the combustion of fossil fuels for energy.
According to the Intergovernmental Panel on Climate Change, there is an urgent need to begin the sustained reduction of carbon dioxide and other greenhouse gases so that global warming is contained to 1.5 °C above the pre-industrial era¹. The United Nations Sustainable Development Goal 7 (SDG7) also calls for providing access to affordable, reliable, sustainable, and modern energy to achieve sustainability goals². Transitioning to cleaner energy sources would help reduce climate change’s impacts and achieve certain SDGs.
Among all RES technologies, solar photovoltaic systems draw wide attention due to their scalability, declining costs, and abundance of solar energy. Solar PV-based microgrids will be especially viable for decentralized power generation in off-grid or remote areas. Combined with other energy sources like wind or BESS, these systems will form hybrid microgrids that ensure better energy reliability and flexibility³. While hybrid microgrids facilitate the world toward sustainable energy on one side, they support the reduction of greenhouse gas emissions by offsetting conventional reliance on fossil fuel-based energy generation. However, integrating solar PV systems and hybrid microgrids presents several technical challenges, particularly regarding power quality. Non-linear loads, very common in the modern grid due to the wide use of power electronics, present serious power quality problems⁴. These loads draw non-sinusoidal currents, creating harmonic distortions that increase system losses, overheating equipment, and reduce efficiency. Addressing these power quality challenges is important to ensure smooth operation for solar PV and hybrid microgrids since these systems are expected to deal with increasingly variable loads.
Some of the advanced filtering techniques used to mitigate THD are Shunt Active Power Filters and hybrid filters^5,6. Integrating BESS with solar PV systems allows for balancing energy supply and demand more effectively under fluctuating load conditions. It describes the need to develop a framework for a grid-tied 100 kW solar photo-voltaic system integrated with a BESS, followed by assessing its performance against various operational modes. Accordingly, the paper aims to determine the non-linear load impacts on the power quality and find optimum solutions for mitigating the same contribution to the sustainability and reliability of renewable energy-based microgrids.
Notwithstanding the increased research on integrating renewable energy sources, a proper critical analysis of various topics still shows several gaps that need to be targeted. The research gaps identified are discussed herein.
Limited exploration of the impact of Battery Energy Storage Systems integration on total harmonic distortion levels, especially under varying nonlinear loads.
Lack of comprehensive analysis of hybrid filters when using solar photovoltaic (PV) systems, BESS, and utility grids.
Inadequate recommendations exist for energy management mechanisms in a solar-based system during periods of low irradiance under high nonlinear loads.
Lack of clarity on the optimal utilization of BESS or the utility grid during periods of low solar irradiance.
There is limited research on comparing BESS and Shunt Active Power Filter performance for THD reduction against standalone solar PV and utility grid supply.
Insufficient analysis of the THD levels within the grid under various situations to find effective methods of THD mitigation.
Inadequate assessment of the effectiveness of hybrid filters for reducing THD levels under conditions of maximum nonlinear load, which is particularly important when compared with stand-alone solar PV systems.
Yuan et al.⁷ studied the harmonic losses in low-voltage distribution networks with integrated distributed PV systems. The results reflect that harmonic losses are around 0.6% of the overall network loss to develop good voltage quality with smaller harmonic distortion and reduce line loss. Ahsan et al.⁸ investigated the power quality issues in an LV network with integrated PV and concluded that the total harmonic distortion in the current and voltage at the PCC are within the IEEE benchmarks for LV, with values of 5% and 10.2%, respectively, for 50% PV penetration. Al-Sharif et al.⁹ detailed the harmonics and voltage fluctuations for grid-connected PV rooftops and the development of a single-tuned filter for harmonic reduction of a 9570 kW PV microgrid. The findings show that the suggested filtration method improves power quality for grid-connected PV systems, meeting the IEEE standards for an LV network. Djeghader et al.¹⁰ proposed a passive filtering approach for nonlinear loads that cause harmonics in the grid: a case study about a nonlinear load with ratings of 11.8 kW is provided. The simulation testing results indicate that different passive filtering schemes reduce the THD significantly, lying in the range of 10.1% to 4.23%. Mishra et al.¹¹, on the other hand, proposed a two-stage, three-phase grid-connected solar photo-voltaic system using an LCL filter, which provides power quality improvement at the front end with THD coming out as low as 1.70% to the maximum allowable of 5%. Zaro et al.¹² investigated a SAPF to enhance the power quality issues in an industrial smart grid, usually caused by photovoltaic inverters and other nonlinear loads. The results indicate that using SAPF reduced the THD in the supply current and can further correct the reactive power compensation and improve the power factor. It was concluded that the SAPF may be one of the solutions to Power Quality Management, system efficiency improvement, and real-time change responses over the grid, mainly due to renewable energy systems. Imam et al.¹³ developed an active power filter with a shunt for power quality enhancement, showing a significant improvement in current THD from 17 to 2.4%, thus meeting IEEE standards. Devassy et al.¹⁴ proposed a system containing a shunt and a series of active filters connected back-to-back with a common DC link. The idea was to solve the integration of power quality improvement with clean energy generation. This system provides continuous power supply to critical loads irrespective of grid availability. Successful operation of the system under various dynamic conditions is demonstrated. Reguieg et al.¹⁵ designed a smart controller integrating series and shunt active filters in a PV-based UPQC to address power quality issues under dynamic nonlinear loads. Their system reduced source current THD to 1.35% and source voltage THD to 1.12%, ensuring compliance with IEEE standards. The hybrid approach demonstrated strong adaptability and performance in maintaining grid stability. Salem et al.¹⁶ studied the integration of solar PV and conventional networks and the power quality issues arising from intermittency in solar and grid-related aspects. A case study was proposed on a 5.5 kW grid-connected PV system, with the investigation of four harmonic mitigation measures. The study attained a current harmonic limitation of 1.5%, which kept the total harmonic distortion below the threshold of 5%. Reguieg et al.¹⁷ proposed a Unified Power Quality Conditioner (UPQC) to mitigate harmonics in grid-integrated PV and wind systems under nonlinear loads. The system achieved a reduction in current THD from over 55% to 1.66–2.23%, and voltage THD from 9.8 to 1.07%. Their dual-control UPQC design ensures improved power quality and grid stability even in extreme conditions.
Lipták et al.¹⁸ discussed the operational problems of large photovoltaic systems connected to utility networks, considering total harmonic distortion with variable solar irradiance levels. Results indicated that, at 820 W/m² irradiances, the total harmonic distortion of the current was 5%, while at lower irradiance of 350 W/m², it increased to 15%, suggesting the need for better inverter control to meet the IEEE 519-2014 standard. Tandon et al.¹⁹ developed a harmonic current controller and an appropriate corrective gating sequence for the IGBT inverter, which resulted in mitigation of the harmonic components and compensation for reactive power. The instantaneous active and reactive power theory-based simulation results showed a considerable reduction of harmonics from the SAPF, reflecting better system performance, especially in networks characterized by nonlinear loads. Souza et al.²⁰ further generalized the MPC concept with FS to SAPFs that enable sinusoidal grid current for high power factors. Experimental results show improved total harmonic distortion levels, conduction, switching, and DC-link loss reduction, demonstrating good response during transients caused by load removal. Chauhan et al.²¹ integrated BESS with a microgrid for rural electrification. Digital filters were utilized to alleviate harmonics in load voltage, achieving sustained voltage and frequency for non-linear loads with PR control. Results demonstrated a total harmonic distortion of load voltage below 5%, meeting the IEEE 519-2014 standard. Reguieg et al.²² proposed a robust Direct Power Control (DPC) strategy combined with a PV-powered shunt APF. Their simulations show that, under varying loads, the scheme—using P&O-MPPT for energy extraction and adaptive harmonic compensation—significantly reduces THD while maintaining stability in grid-connected renewable systems.
Apeh et al.²³ discussed that PV systems are growing at an increasing rate and reached a capacity of 37.6 GW in 2017, reaching 600 GW by 2030 and 4500 GW by 2050. Tax credits and subsidies underline the role of government policies in this development. The results suggested that solar energy would create about 10 million permanent jobs per year while considerable investments and policy support could unfold various opportunities regarding the full environmental and financial value of such technologies. Bashiru et al.²⁴ presented the imperative need for transitioning towards renewable energy sources concerning global energy demands and environmental sustainability. RES are emphasized not only for its contribution to emission reduction and energy security but also for pinpointing the challenges: market failures and material constraints. This conclusion was made after policy recommendations that call for a collaborative approach to overcoming such barriers toward attaining sustainable development goals. Basit et al.²⁵ analyzed the environmental and economic viability of RES and their application in microgrid systems. Their study demonstrates that integrating RES into microgrids can achieve colossal savings in GHG emissions and peak energy costs, tame fluctuation of load demands, and reduce losses on the load side. Kar et al.²⁶ assessed the on-grid BESS opportunity for the efficiency and stability of modern electrical power grids. BESS helps balance demand and supply by absorbing excess electricity whenever demand is low and releasing it during the peak or when the generation of variable renewable sources is low. The simulation results prove that BESS is functional and important for sustainability, carbon emission reduction, and grid reliability. Ensuring supply quality within its standard limit is a critical challenge nowadays due to the vast integration of PV systems in low-voltage networks. Mansor et al.²⁷ examined the use of a Unified Power Quality Conditioner (UPQC) supported by a PV system and a Battery Energy Storage System (BESS) to mitigate power quality problems in the grid. Results indicated that the hybrid PV-BESS system is more reliable than a standalone PV-UPQC system. Chapala et al.²⁸ simulated a grid-connected solar PV system with a UPQC-integrated battery. The operation, carried out in various surrounding situations, improved the grid current’s total harmonic distortion from 28.6% to 3.7% under unbalanced load conditions with the PV-battery-integrated UPQC system. Jain et al.²⁹ proposed an improved control strategy for a PV-based UPQC integrated with BESS to enhance power quality under nonlinear and unbalanced load conditions. Their hybrid Hysteresis-MPPT approach achieved a reduction in current THD to 1.86% and voltage THD to 0.91%. The system proved effective in maintaining voltage stability and mitigating harmonics during dynamic disturbances.
In order to solve the above-mentioned research gaps, the following contributions have been made to the proposed study:
Three key extensions to existing PV-BESS and THD-control knowledge are provided by this research. First, a unified two-stage Genetic-Algorithm framework is developed that simultaneously optimizes hourly source allocation (PV, BESS, grid) and the minimum required filter deployment (SAPF versus hybrid) to guarantee IEEE 519 compliance, whereas in prior work these tasks are treated separately. Second, a comprehensive set of non-linear load mixes and operating modes (grid-tied PV, PV + BESS charging, BESS-only, grid-only) is evaluated, and the influence of dynamic load profiles on harmonic generation is quantified; it is shown that BESS paired with SAPF alone maintains sub-5% THD under conditions that defeat conventional PV or grid supply. Finally, the “best source-filter pairing” is identified across all scenarios, demonstrating that BESS + SAPF suffices, PV requires SAPF with load-current referencing, and the grid demands hybrid filtering, thereby providing actionable design guidelines that have not previously been codified.
Investigates the impact of Battery Energy Storage Systems (BESS) integration on total harmonic distortion (THD) levels, particularly under varying non-linear loads.
Provides a comprehensive analysis of the hybrid filters when using solar-photovoltaic (PV) systems, BESS, and utility grids.
Presents recommendations on energy management during low solar radiation where nonlinear loads are high.
Explores the best utilization strategies for either BESS or the utility grid during periods of low solar irradiance.
Compares the performance of BESS with Shunt Active Power Filters for reducing THD against standalone solar PV systems or utility grid supply.
It evaluates the levels of THD within the grid with respect to different scenarios in quest of effective methods for the mitigation of THD.
Assesses the performance of hybrid filters at maximum nonlinear load for mitigating THD levels, with particular emphasis on a standalone solar PV system.
The rest of the paper is organized as follows: Section “Materials and methods” briefly describes the materials and methodology used by the proposed study. Section “Results and discussion” discusses the study results and analysis based on the outcome of the studies. Section “Conclusion” concludes the paper.
In the proposed study, the modelling of a hybrid microgrid is considered, and the Power Quality Improvement is implemented by designing a Passive Filter and a Shunt Active Power Filter using the MATLAB/Simulink R2023b environment. The filters will be implemented in MATLAB to improve total harmonic distortion in the microgrid’s current, as needed.
A Photovoltaic (PV) cell is an electronic component that produces electricity when exposed to the irradiance and temperature of sunlight intensity. When different PV cells are combined, they form a solar panel utilized in different applications to produce electrical energy. The PV is set to give maximum power using a boost converter and MPPT controller. The boost converter is a static converter that acts as an adapter between the PV generators and the load to collect the maximum power generated and transfer it to the load. The MPPT controls the boost converter to achieve maximum efficiency³⁰. Equations 1 and 2 are used for modelling the PV cell. The solar PV with utilized system parameters has shown in Table 1.
Lithium-ion batteries have been utilized in the proposed study as they have better efficiency and reliability than other battery models. The Battery Energy Storage System (BESS) is a backup agent that balances the supply and demand ratio. The BESS model comprises a Li-ion battery connected to a bi-directional DC to DC-buck-boost converter and a PID controller. The buck-boost converter is a bi-directional DC-DC converter that can provide the power flow between the microgrid and battery. In the case of charging, the battery acts as a load, while in the case of the discharging state, the battery acts as a DC source³¹. A PID controller that regulates the charging-discharging can manage the balance between BESS and microgrid power infrastructure.
In the proposed research, a three-phase H-bridge inverter, shown in Fig. 1, is designed to have precise output voltage and frequency control³². The inverter’s control structure may refer to grid or load current. The approaches used in the proposed study are fundamental when determining how inverter control affects power quality and again highlight the importance of an optimized control system design to achieve higher performance. When grid current is used as a reference, the inverter regulates its output based on the grid to supply voltage and frequency regulation, reactive power compensation, and power factor correction. This may result in underestimating the real load variations in some applications.
Three phase H-bridge inverter.
On the other hand, taking load current as a reference makes the inverter respond directly to the demands of the load with high efficiency and performance, especially for those systems with fluctuating loads³³. This may require more careful coordination with the grid control mechanisms to maintain stability and comply with the grid regulations. The choice between grid and load current references depends on the system design, control objectives, and load characteristics. In some cases, both can be used together to reach an optimum between grid support and load responsiveness.
The utility grid in the proposed study is connected to a 60-kW load, comprising both linear and non-linear loads. The utility grid allows the load demand to be uninterrupted.
Unlike linear loads, non-linear loads draw a non-sinusoidal current from a sinusoidal voltage supply. The distortion to the normal incoming sinusoidal current wave can be considered to result from the load emitting harmonic currents that distort the incoming current. The filters utilized in the proposed are classified into passive and shunt active filters.
Passive filters have easy design, simple structure, low cost, and high efficiency. These generally consist of banks of tuned LC filters that suppress the current harmonics produced by nonlinear loads³⁴, as depicted in Fig. 2.
Double tuned passive filters.
Shunt Active Power Filters are applied to compensate for current harmonics to reduce THD and improve the input power factor to overcome the disadvantages of Passive Filters. A three-phase SAPF consists of a bridge converter and control circuitry, as shown in Fig. 3. The SAPFs are connected in parallel with nonlinear loads and inject harmonic current of the same amplitude but opposite phase with respect to the load harmonics. Due to this, sinusoidal line currents are obtained with a unity power factor³⁵.
Shunt active power filter compensation³⁶.
In Fig. 4, SAPF employs a PWM voltage source inverter to sense the harmonics in the source current and generate the compensating current injected through the PCC. It reduces harmonics, eliminates unwanted frequencies, compensates for reactive power, and corrects waveforms. The SAPF is connected parallel between the load and filter using a DC source³⁷.
Internal circuitry of Shunt Active Power Filter.
The control strategies calculate the compensating current based on waveform, frequency, and time domain analysis. Some techniques, such as the PQ method, operate SAPFs in transient and steady states. In the Hysteresis Current Control feedback PWM method, the actual current tracks the command current within a hysteresis band to ensure dynamic response, ease of implementation, and low cost³⁸.
The PQ theory is utilized to determine active and instantaneous reactive current components. This strategy uses the first Clarke Transform shift current load and source voltage. The two-phase calculation method converts the three-phase measurements into a two-phase model (α & β) using the Clarke transform³⁹.
Both instantaneous real power (P) and instantaneous reactive power (Q) can be calculated by:
where:
P and Q are the average components of real and reactive powers, respectively. The reference compensating currents Ia* and Ib* in a two-phased model can be calculated by:
Compensating current in a three-phased model is mandatory for a three-phased inverter and can be evaluated by applying inverse Clarke transformation:
The basic working principle of the HCC technique is illustrated in Fig. 5. The Hysteresis Current Control (HCC) technique is an instantaneous feedback current control method of PWM, where the current continually tracks the command current within a hysteresis band⁴⁰.
Hysteresis controller’s band⁴¹.
Figure 6 shows a six-pulse generation scheme for driving the inverter switches. The inverter output current follows the reference current through pulses generated by the hysteresis controller. In phase-a, if i_ca exceeds the upper hysteresis limit, the comparator output is 0; if below the lower limit, the output is 1. The current deviates within the hysteresis band around the reference current.
PWM generation scheme for SAPF’s inverter.
The microgrid consists of a 100 kW three-phase grid-tied PV array, a 60 kWh Li-ion BESS, a common DC bus, a three-phase voltage source inverter (VSI) interfacing the PCC with the utility grid, and Power Quality (PQ) devices: a Shunt Active Power Filter (SAPF) and (where needed) a hybrid filter (SAPF + tuned passive LC). Mixed loads include: (i) aggregated linear loads P_LL∈[10,60] kW and (ii) a three-phase uncontrolled diode bridge rectifier feeding an RL load (P_NLL∈ [0,50] kW) generating current harmonics. The PV array feeds the DC bus via its DC/DC MPPT stage; the BESS connects through a bi-directional DC/DC converter enabling controlled charge/discharge. The SAPF is a current-controlled shunt VSI tied in parallel at the PCC (or embedded logically within the main inverter with separated control layers if a single hardware platform is assumed).
Voltage levels DC bus nominal ({text{V}}_{text{dc}}^{text{ref}})(700–800 V) selected to ensure modulation index margin at worst-case AC line voltage sag and to accommodate SAPF current injection headroom.
Let P_PV, P^dc_BESS, P_Grid, P_Load (P_LL + P_NLL), and P_Loss denote instantaneous active powers (positive from source perspective). Power balance on the DC bus (neglecting small capacitor ripple) is:
Modes:
Grid-tied PV (no BESS charge) P_PV supplies load; surplus exported: P_Grid < 0.
PV + BESS charging
BESS discharge (Island)
Grid only
Hybrid with filters SAPF / hybrid injects harmonic and (optionally) reactive currents: ({P}_{SAPF}approx 0) (ideally only reactive/ harmonic compensation) while maintaining its DC link.
A DC/DC boost converter regulates PV array operation. The Perturb & Observe (P&O) MPPT updates duty ratio D_PV based on incremental power change ΔP_PV and voltage step ΔV_PV:
If (Delta {P}_{PV}/Delta {V}_{PV}>0), continue perturb direction, else reverse. A low-pass filtered PV current I_PV and voltage V_PV provide power ({P}_{PV}={V}_{PV}{I}_{PV}). MPPT bandwidth is set lower than DC bus regulation loop to avoid interaction (e.g. MPPT update every few milliseconds vs DC bus loop at kHz).
The BESS DC/DC (half-bridge or full-bridge) enforces commanded charge/discharge current ({I}_{BESS}^{ref}) derived from SoC control and system power balance:
SoC update:
A cascaded loop: outer DC bus or SoC regulator sets power/current reference, inner fast current loop (PI/PID) controls inductor current. PID gains K_p, K_i, K_d were selected via:
Small-signal linearization of converter around nominal current.
Fine tuning to achieve less than 5% overshoot and less than 10 ms settling time under ± 20% rated current steps.
A three-phase VSI with Sinusoidal PWM or Space Vector Modulation regulates grid currents. Two reference generation modes:
Grid Current Referencing Set ({i}_{abc}^{ref}) to deliver scheduled active power ({P}^{ref}) (and optionally zero reactive) aligning d-axis current.
Load Current Referencing Measure load current ({i}_{L,abc}), and extract fundamental positive sequence component ({i}_{L,abc}^{fund}) (via synchronous reference frame (SRF) PLL). Command inverter to supply that fundamental portion: ({i}_{abc}^{ref}={i}_{L,abc}^{fund})​, shifting harmonic/residual components to SAPF or grid depending on mode, lowering grid-side THD.
A PLL estimates grid angle θ. Following shows the dq current control equations:
Similarly for q-axis, feedforward of grid voltage accelerates dynamic response.
Adaptive reference mode switching To enhance inverter performance under varying harmonic distortion, a supervisory scheme dynamically switches between reference modes:
Measure THD Compute current THD over a sliding window (e.g., 100 ms).
Mode decision
THD ≤ 3%: use grid-current referencing
THD ≥ 5%: use load-current referencing
3% < THD < 5%: hold current mode
Smooth transition Blend references over 20 ms to avoid transients.
This adaptive logic minimizes unnecessary filter activation and ensures IEEE 519–2014 compliance under dynamic loads.
The SAPF measures load (or grid) currents ({i}_{L,abc}) . Harmonic reference extraction uses p–q theory or SRF method (describe chosen one):
SRF method Transform ({i}_{abc}to {i}_{dq}) using PLL angle. Low-pass filter fundamental components (widetilde{{i}_{d}}), (widetilde{{i}_{q}}). Harmonic components: ({i}_{d}^{h}={i}_{d}-widetilde{{i}_{d}}) , ({i}_{q}^{h}={i}_{q}-widetilde{{i}_{q}}). Inverse transform yields harmonic current reference ({i}_{h,abc}^{ref}). SAPF commands injection ({i}_{f,abc}^{ref}=-{i}_{h,abc}^{ref}).
A DC link voltage regulator ensures SAPF internal DC capacitor voltage ({V}_{dc,f}approx {V}_{dc,f}^{ref}):
Its fundamental active current component is superimposed to compensate internal losses.
When high, concentrated harmonic orders (e.g. 5th, 7th) dominate and SAPF current rating would be exceeded or residual THD > 5%, a tuned LC branch provides low-impedance paths for selected orders. The SAPF then focuses on residual/uncharacteristic harmonics and dynamic components, lowering its current stress and switching losses. Following are the Passive filter reactances:
A two-stage Genetic Algorithm (GA) provides hourly decisions over a 24-h horizon.
For each hour t, gene pair (S_t, F_t) where St ∈ {PV, BESS, Grid}, Ft {0 = No Filter, 1 = SAPF, 2 = Hybrid}. Stage 1 fixes F_t = 0, to obtain minimal raw THD schedule; hours where THD_t > 5% are flagged. Stage 2 releases F_t only for flagged hours, allowing escalation to SAPF or Hybrid while possibly re-selecting source S_t to reduce total filter hours.
The GA is configured with a population size of 50 and allowed to run for 100 generations, which is sufficient for convergence in the proposed study. Tournament selection has been in the GA (tournament size = 3), single-point crossover with probability p_c = 0.8, and bit-flip mutation with probability p_m = 0.02. The fitness function was defined to minimize three key objectives:
maximum hourly THD, average THD, and total filter usage, while penalizing source switching.
where N_switch penalizes source transitions; H_SAPF; H_Hybrid are total activated hours; w_i chosen (e.g. w₁ > w₂) to enforce IEEE 519 constraint priority.
Tournament selection, single-point crossover (prob. p_c ), mutation on gene pairs (prob. p_m ) with feasibility repair (enforcing PV availability window and BESS SoC bounds). Convergence when max_t (THDtle 5%) and improvement < ε over N generations.
Update irradiance & load forecast → availability constraints.
GA schedule selects S_t; dispatch command sent to PV/BESS/grid.
Determine reference mode (grid-current or load-current) based on StS_tSt and expected harmonic profile.
Measure instantaneous THD (sliding FFT / IEC window). I_f > 5% and F_t = 0, escalate per GA plan to SAPF; if still > 5%, activate hybrid.
Update SoC and DC bus control loops; ensure SAPF DC link regulation.
Log THD, filter status, energy flows for next GA refinement (if adaptive variant used).
SoC limits SoC_min prevents over-discharge; SoC_max prevents over-charge during high irradiance.
Current limits Inverter and SAPF reference magnitudes saturated to rated currents to avoid over-modulation.
Filter resonance avoidance Damping resistor R_d or active damping control included in hybrid LC design to mitigate parallel resonance with grid impedance.
Primary: Hourly current THD, maximum daily THD, total filter activation hours, energy not served (if any), switching count. Secondary: DC bus voltage deviation, BESS SoC trajectory, SAPF average current utilization, as shown in Fig. 7.
Microgrid comprising of solar PV system, BESS, and grid with loads.
Genetic Algorithms are nature-inspired optimization techniques inspired by the process of natural selection. The method first generates a population of candidate solutions to a problem, with every individual solution termed a chromosome. These undergo an iterative evolution through selection, crossover, and mutation cycles, as depicted in Fig. 8. In each generation, the fittest individuals, evaluated by a fitness function, are chosen to produce offspring for the next generation so that after some time, the algorithm will converge to the optimal or near-optimal solution. Genetic algorithms are especially effective in solving complex, multi-variable optimization problems for which classical analysis methods may be inefficient or impracticable.
Flowchart of a Generic Genetic Algorithm.
In terms of power quality, using GA, power sources and filter configurations are encoded so that different power sources generate different combinations as chromosomes while the fitness function makes each such combination evaluate for its best performance in minimizing THD. Such algorithms are iterative and converge for a blend of power sources and filtering devices to yield optimum microgrid performance. The adaptive approach puts the power quality at its best while keeping system efficiency at its maximum by dynamically acting upon the changing load condition and source availability. Genetic algorithms have proven viable solutions for managing power quality in the microgrid environment through automation of source allocation and filter selection, and hence, they contribute toward grid stability with sustainable energy integration.
In the proposed study, the genetic algorithm has played a significant role in achieving optimal power quality with a minimum THD for the microgrid and analyzing various power sources, such as Solar PV, BESS, and the Grid, operating under widely changing load conditions. In this respect, using GA, the system dynamically chooses the most appropriate power source at every hour of the day and prioritizes the one with the minimum THD. It ensures that standards regarding IEEE 519–2014 are accomplished, where a 5% maximum is allowed on THD. When the THD exceeds the permitted limit, the algorithm will start corrective actions, such as filter reconfiguration or load redistribution, to recover the power quality.
The flowchart illustrated in Fig. 9 is based on a structured methodology for analyzing and attenuating THD in the configuration of a microgrid with various power sources and filtering devices, concerning IEEE 519–2014. This starts with the initialization and parameterization of the microgrid to test different configurations such as Solar PV only, Grid, or both in this case. Its framework branches into three pathways: Battery Energy Storage System, Power Quality-PQ devices such as filters, and BESS with PQ devices. Each configuration is subjected to linear and nonlinear loads, with distribution determined by percentage parity.
Flowchart for microgrid operation and control.
Solar PV charges the BESS in the left branch, which feeds the combination of loads. Then, it is subjected to the THD analysis to see whether it is within the IEEE standard’s limit. If it is within the limit, then the process gets successfully terminated. If it is out of limit, then corrective measures like redistribution of load and filter reconfigurations are performed. The middle branch combines solar PV with either Grid or their combination and integrates with PQ improvement devices so that it can mitigate power quality problems brought about by the presence of non-linear loads that could increase the THD by as many folds. These filters are to minimize such distortions and comply with the standards of power quality. BESS in the rightmost branch is interfaced with PQ devices to feed the complex loads. This hybrid configuration leverages the energy storage benefits while ensuring that THD levels are managed by applying filters. In this regard, THD analysis is an important process in which continuous assessment and iterative improvements are performed until the system meets the required power quality standards.
Only upon the completion of the THD analysis for all the configurations, the successful scenarios pass through the Power Quality check to identify how good the mitigation strategies are when applied. The results are later systematically tabulated and compiled into an integrated dataset, showing THD evaluation results for each tested scenario. The above-structured approach delivers a set of comprehensive evaluations from different configurations; therefore, an optimum configuration combination may come out as one to enhance microgrid power quality.
In the grid-tied mode, the microgrid utilizes a 100-kW solar PV system as its primary source to supply loads and feed surplus energy back into the grid, with no charging of the battery occurring. This study examines four scenarios to assess solar PV’s power quality in grid-tied operation, as shown in Table 2. Additionally, it utilizes data from these scenarios to evaluate total harmonic distortion and determine the necessity of implementing a Shunt Active Power Filter or Hybrid Filter.
A 100 kW PV system is integrated with a utility grid. The PV system supplies 60 kW of power to the Linear & Non-Linear Load and the rest of the 40 kW of power to Grid. The system is tested with different Linear & Non-Linear load values, and %THD of grid current is checked when PV operates under normal inverter operation (without load’s reference in its control) and with the load-controlled inverter. If the %THD of grid current becomes more than 5%, i.e., the rated IEEE 519–2014 power quality standard, then the shunt Active Power Filter caters to those harmonics. If the %THD still does not get into the required range of harmonics, then a hybrid filter (combination of Shunt APF and tuned Passive filter) is used to lower those harmonics and make sure that the system follows the IEEE 519–2014 standard so that the power quality does not get compromised. The improvement of power quality between SAPF, passive Filter, and hybrid filter (combination of SAPF and passive filter) is also compared. The THD analysis and results for four different percentages of loads have been discussed as follows:
In Figs. 10, 11, 12, Active Power of all the sources, Grid current, and Load currents are shown respectively. As the 60-kW load comprises a Linear Load, no non-linearity is observed while performing the FFT analysis of the grid current as shown in Fig. 13a–c, where the PV side inverter does not use load current for generating current reference, total harmonic distortion comes out to be 1.23%, whereas, in Fig. 13d, THD comes out to be 0.3%. As the grid current’s THD is well below 5%, there is no need to use active power filters, passive filters, or hybrid filters.
Power of sources and loads.
Grid current with 100% linear load.
Linear & non-linear load current.
Grid current comparison under different inverter control’s reference conditions (a) Ig as reference (b) IL as reference; %THD (c) Ig as reference (d) IL as reference.
In this scenario, 60 kW of total load is divided into 45 kW of linear load and 15 kW of non-linear load, as shown in Fig. 14. The non-linear load draws a non-sinusoidal current, making the current going into the grid non-linear, as shown in Figs. 15, 16, respectively. FFT analysis of the grid current is performed to observe the total harmonic distortion that the 15-kW non-linear load adds to the system. Figure 17a, b shows grid current comparison under different Inverter control’s reference conditions. In Fig. 17c, where the PV side inverter does not use load current for generating current reference, total harmonic distortion comes out to be 7.49%, more than 5%. Hence, it violates the IEEE 519–2014 standard. Meanwhile, in Fig. 17d, where the load current’s reference is generated, THD comes out to be 4.03%. No filter is used in this case, as the grid current’s THD in Fig. 17d is still below 5%.
(A) PV power (B) Power supplied to the grid (C) Total load power (D) Linear load power (E) Non-linear load power.
Grid current with 75% linear load, 15% Non-linear load.
(a) Linear load current (b) Non-linear load current.
Grid current comparison under different inverter control’s reference conditions (a) Ig as reference (b) IL as reference; %THD (c) Ig as reference (d) IL as reference.
In this scenario, a 60-kW load is divided into 30 kW of linear load and 30 kW of non-linear load, as shown in Fig. 18. The non-linear load draws a non-sinusoidal current, making the grid current non-linear, as shown in Fig. 19. The difference between the sine waves of Grid Current in different scenarios is illustrated in Fig. 20. FFT analysis of the grid current is performed to observe the amount of THD that the 30-kW non-linear load adds to the system. In Fig. 21a, where the PV side inverter does not use load current for generating current reference, total harmonic distortion comes out to be 24.86%, more than 5%. Hence, it violates the IEEE 519–2014 standard. Meanwhile, in Fig. 21b, where the load current’s reference is generated, THD comes out to be 13.19%. As the grid current’s THD in Fig. 21b is still above the threshold of 5%, so there is a need to use a filter to mitigate the excess harmonics of the system. Thus, the Shunt Active Power Filter (SAPF) is used in Fig. 21c. SAPF successfully reduces the THD of grid current to 3.87%, under the threshold value.
(A) PV Power (B) Power supplied to the grid (C) Total load power (D) Linear load power (E) Non-linear load power.
Grid current with 50% linear load, 50% non-linear load.
Grid current when (a) Ig is taken as reference, (b) IL is taken as reference, (c) SAPF is applied.
%THD of grid current when (a) Ig is taken as reference, (b) IL is taken as reference, (c) SAPF is applied.
In this scenario, 60 kW load is divided into 12 kW of linear load and 48 kW of non-linear load, as shown in Fig. 22s. The difference in the waveform of Grid Current in different scenarios is depicted in Fig. 23. FFT analysis of the grid current is performed to observe the amount of THD that the 48-kW non-linear load adds to the system. In Fig. 24a, where the PV side inverter does not use load current for generating current reference, total harmonic distortion comes out to be 45.79%, more than 5%. Hence, it violates the IEEE 519–2014 standard. Meanwhile, in Fig. 24b, where the load current’s reference is generated, THD comes out to be 26.68%. As the grid current’s THD in Fig. 24b is still above the threshold of 5%, a filter is needed to mitigate the excess harmonics. In Fig. 24c SAPF mitigates the harmonics. The THD comes out to be 8.16%, violating the IEEE 519–2014 standard. So, Hybrid Filter is used in Fig. 24d. It successfully reduces the THD of the grid current to 4.76%, which is under the threshold value.
(A) PV power (B) Power supplied to the grid (C) Total load power (D) Linear load power (E) Non-linear load power.
Grid current when (a) Ig is taken as reference, (b) IL is taken as reference, (c) SAPF is applied, (d) Hybrid filter is applied.
%THD of grid current when (a) Ig is taken as reference, (b) IL is taken as reference, (c) SAPF is applied, (d) Hybrid filter is applied.
In this scenario, the linear load is 45 kW, and the non-linear load is 15 kW. When solar irradiance reduces, the fundamental current component decreases correspondingly, rendering total harmonic distortion (%THD) ineffective for measuring power quality. Hence, Total Demand Distortion (%TDD) is employed during this period. Despite the consistency in overall demand, TDD does exhibit a slight variation, shifting from 4.03 to 3.73%, as shown in Fig. 25.
(a) PV irradiance (b) %TDD of the grid current.
In this case, BESS is added to the 100-kW grid-tied solar PV system. The microgrid utilizes solar PV as its primary power source to supply loads, charge BESS with the surplus energy and feed the rest of surplus energy, if present, back into the grid. This study examines four scenarios to assess solar PV’s power quality in grid-tied operation with BESS as an additional load, as shown in Table 3. Additionally, it utilizes data from these scenarios to evaluate total harmonic distortion and determine the necessity of implementing a Shunt Active Power Filter or Hybrid Filter.
Of the 100 kW of solar PV power that is available, 60 kW is used by linear loads, and 10 kW of power is used by the battery to charge it. The remaining 30 kW of power is fed into the grid, as in Fig. 26. Different control strategies for the Inverter are illustrated in Fig. 27. When the grid current is analyzed using the FFT analysis, no non-linearity is found because the 60-kW load is entirely composed of linear load. Total harmonic distortion (THD) is found to be 0.54% in Fig. 28a, when the PV side inverter does not employ load current to provide current reference, and 0.39% in Fig. 28b. There is no need to use hybrid, passive, or active power filters because the grid current’s THD is far below 5%.
(A) PV power (B) Power supplied to the grid (C) Total load power (D) Linear load power (E) Non-linear load power.
Grid current when (a) Ig is taken as reference (b) IL is taken as reference.
%THD of grid current when (a) Ig is taken as reference (b) IL is taken as reference.
In this case, a 60-kW load is split into a 45-kW linear load and a 15-kW non-linear load. 10 kW of the total PV power is supplied to the battery for charging. The remaining 30 kW of power is fed into the grid, as shown in Fig. 29. The behavior of Grid current in different scenarios is illustrated in Fig. 30. To see how much THD is added to the system by the 15 kW non-linear load and battery charger, an FFT analysis of the grid current is carried out. The total harmonic distortion in Fig. 31(a), where the PV side inverter does not use load current for generating current reference, is 8.89%, above the 5% threshold. As a result, it violates the IEEE 519–2014 standard. Whereas in Fig. 31(b), THD equals 7.53%, where the load current reference is generated. The grid current’s THD in Fig. 31(b) is still higher than the 5% threshold. Therefore, Shunt Active Power Filter (SAPF) is used in Fig. 31(c). Grid current’s THD is successfully lowered by SAPF to 1.6%, well below the limit.
(A) PV power (B) Power supplied to the grid (C)Total load power (D) Linear load power (E) Non-linear load power.
Grid current when (a) Ig is taken as reference (b) IL is taken as reference (c) SAPF is applied.
%THD of grid current when (a) Ig is taken as reference (b) IL is taken as reference (c) SAPF is applied.
In this scenario, 60 kW load is divided into a 30-kW linear load and a 30-kW non-linear load. The battery receives 10 kW of the total PV power for charging. 30 kW of the remaining power is supplied to the grid, as shown in Fig. 32. The difference in the waveforms of Grid current in various scenarios is shown in Fig. 33. An FFT analysis of the grid current is performed to determine how much THD is added to the system by the 30 kW non-linear load and the battery charger. When the PV side inverter does not use load current to provide current reference, as in Fig. 34a, the total harmonic distortion comes out to be 23.59%, which is higher than the 5% standard. It thereby transgresses the IEEE 519–2014 standard. Whereas in Fig. 34b, when the load current reference is generated, it has a THD of 21.79%. The THD of the grid current in Fig. 34b is significantly greater than the 5% cutoff. As a result, Fig. 34c uses a Shunt Active Power Filter. SAPF successfully reduces the THD of grid current to 4.68%, hence satisfies the standard limits.
(A) PV power (B) Power supplied to the grid (C)Total load power (D) Linear load power (E) Non-linear load power.
Grid current when (a) Ig is taken as reference (b) IL is taken as reference (c) SAPF is applied.
%THD of grid current when (a) Ig is taken as reference (b) IL is taken as reference (c) SAPF is applied.
A 60-kW load in this case is split into a 12-kW linear load and a 48-kW non-linear load, as shown in Fig. 35. The different waveforms of Grid Current in different scenarios are depicted in Fig. 36. The total harmonic distortion in Fig. 37(a), where the PV side inverter does not employ load current for generating current reference is at 46.66%, greater than 5% limit. As a result, it defies IEEE 519–2014. In contrast, THD is found to be 41.47% in Fig. 37b, where the load current’s reference is generated. Filters must be used to reduce the surplus harmonics because the grid current’s THD in Fig. 37b is still higher than the 5% standard. SAPF is utilized in Fig. 37c to reduce the harmonics. THD comes out to be 10.48%, violating the IEEE 519–2014 standards. Thus, hybrid filters are being used in Fig. 37d. Grid current’s THD is successfully lowered to 4.79%, which is below the threshold. The 48-kW non-linear load and the battery charger as shown in Fig. 38, contribute a certain amount of THD to the system, which is observed by FFT analysis of the grid current.
(A) PV power (B) Power supplied to the grid (C)Total load power (D) Linear load power (E) Non-linear load power.
Grid current when (a) Ig is taken as reference (b) IL is taken as reference (c) SAPF is applied (d) Hybrid filter is applied.
%THD of grid current when (a) Ig is taken as reference (b) IL is taken as reference (c) SAPF is applied (d) Hybrid filter is applied.
(A) Battery’s current while charging (B) Battery’s SOC during charging (C) Power taken by the battery during charging.
In this scenario, the linear load is 30 kW, and non-linear load is 30 kW, and a Shunt Active Power Filter (SAPF) is connected with it. When solar irradiance level reduces from 1000 to 800 W/m², the fundamental component of current decreases correspondingly, rendering total harmonic distortion (%THD) ineffective for measuring power quality. Hence, Total Demand Distortion (%TDD) is employed during this period. Despite the consistency in overall demand, TDD does exhibit a slight variation, shifting from 20.44 to 18.79%, as shown in Fig. 39.
(a) PV irradiance (b) %THD of the grid current.
In this case, BESS is used as a primary power source to supply the loads while solar PV system and grid are absent. This study examines four different scenarios to assess the power quality of the input power of the BESS’s inverter, which ultimately feeds the loads as shown in Table 4. Additionally, it utilizes data from these scenarios to evaluate total harmonic distortion and determine the necessity of implementing Shunt Active Power Filter or Hybrid Filter.
In this case, neither PV nor grid power is available. The 60-kW linear load is supplied by a 60-kWh battery energy storage system (BESS). Unlike in prior cases, where the grid was connected to the system, no power is sent to the grid. The BESS delivers dc power, which is converted to ac power using an h-bridge inverter. The input voltage and current of this inverter are analyzed using FFT. There is no nonlinearity observed as the 60-kW load is fully linear. The total harmonic distortion (THD) of voltage is 0.64%, and the THD of current also comes out to be 0.64%, as in Fig. 40. Hence, the power quality standard is being observed.
(a) Inverter side Voltage Vin (b) Inverter side Current Iin (c) %THD of Inverter’s Voltage (d) %THD of inverter’s current.
In this scenario, the 60-kW load is divided into 45 kW of linear load and 15 kW of nonlinear load. The entire load is supplied by a 60-kWh battery energy storage system (BESS). Therefore, no power is transferred to the grid. The input voltage and current of BESS-connected inverter are analyzed using FFT. Total harmonic distortion (THD) of input voltage comes out to be 5.06%, which is less than the 8% limit of the IEEE 519–2014 power quality standard for voltage, and current THD is 3.73%, as in Fig. 41, which is less than the 5% limit of the IEEE 519–2014 power quality standard for current. Consequently, the power quality requirement is being followed.
(a) Inverter side Voltage Vin (b) Inverter side Current Iin (c) %THD of Inverter’s Voltage (d) %THD of Inverter’s Current.
In this scenario, the 60-kW load is divided into 30 kW of linear load and 30 kW of nonlinear load. A 60-kWh battery energy storage system (BESS) supplies the whole load. Thus, no electricity is fed into the grid. The output voltage and current waveforms are shown in Fig. 42. FFT is used to analyze the input voltage and current of the BESS-connected inverter. The results show that the input voltage’s total harmonic distortion (THD) is 10.82% higher than the standard voltage limit and the current THD is 7.72% higher than the standard current limit. To reduce these high harmonics, Shunt Active Power Filter (SAPF) is employed. The input voltage and current’s %THD after connecting SAPF are 2.63% and 1.96%, respectively, as in Fig. 43. As a result, the criteria for power quality is being met.
(a) Inverter side Voltage Vin (b) Inverter side Current Iin (c) Inverter side Voltage Vin with SAPF (d) Inverter side Current Iin with SAPF.
%THD of (a) Inverter’s Voltage (b) Inverter’s Current (c) Inverter’s Voltage with SAPF (d) Inverter’s Current with SAPF.
In this case, the 60-kW load is split into a linear load of 12 kW and a nonlinear load of 48 kW. The entire load is supplied by a 60-kWh battery energy storage system (BESS). The input voltage and current of the inverter, as in Fig. 44 linked to the BESS are analyzed using FFT. The total harmonic distortion (THD) of the input voltage is 16.01%, greater than the standard voltage limit, and the THD of the current is 11.43% (Fig. 45), higher than the standard current limit, according to the IEEE 519–2014 standard. The use of SAPF lowers these high harmonics. After connecting SAPF, the input voltage and current have %THD values of 3.05% and 2.62%, respectively, as in Fig. 45. Consequently, the requirements for power quality are being fulfilled with BESS working in the discharge mode, as shown in Fig. 46.
(a) Inverter side Voltage Vin (b) Inverter side Current Iin (c) Inverter side Voltage Vin with SAPF (d) inverter side Current Iin with SAPF.
%THD of (a) Inverter’s voltage (b) Inverter’s current (c) Inverter’s voltage with SAPF (d) Inverter’s current with SAPF.
(a) Battery voltage (b) Battery current (c) %SOC of battery (d) Power delivered by battery.
In this case, Grid is the only active power source in the microgrid supplying the loads. The solar PV system and BESS are considered absent. This study examines four different scenarios to assess the power quality supplied by the grid with both linear and non-linear loads. Additionally, it utilizes data from these scenarios to evaluate total harmonic distortion and determine the necessity of implementing Shunt Active Power Filter or Hybrid Filter as shown in Table 5.
A utility grid provides 60 kW of linear load in this case. The system exhibits no non-linearity since the load consists entirely of linear loads. FFT analysis of grid current is also performed to determine the quantity of harmonics, if any. Total harmonic distortion comes out to be zero as in Fig. 47, indicating that load is completely linear, and hence meets the IEEE 519–2014 standard.
(a) Grid current (b) %THD of grid current.
In this case, the 60-kW load is split into 45 kW of linear load and 15 kW of non-linear load. The non-linear load draws non-sinusoidal current, making the grid current non-linear as in Fig. 48a, b. FFT analysis of grid current is used to determine how much overall harmonic distortion the 15 kW non-linear load adds to the system. Total harmonic distortion of grid current comes out to be 7.70%, which exceeds the 5% limit as in Fig. 49a. As a result, it violates the IEEE 519–2014 standard. To reduce the harmonics, SAPF is connected. After applying SAPF, the %THD is reduced to 1.99% as in Fig. 49b, indicating that the standard is now being met.
(a) Actual grid current (b) Grid current when SAPF is connected.
%THD of (a) Grid current (b) Grid current when SAPF is connected.
In this scenario, the 60-kW load is divided into 30 kW of linear and 30 kW of nonlinear load. The 30-kW non-linear load draws non-sinusoidal current, causing the grid current to be nonlinear. Waveforms of the actual grid current and with different filters are shown in Fig. 50. FFT analysis of grid current is performed to estimate how much overall harmonic distortion the 30-kW non-linear load introduces into the system (Fig. 51). The total harmonic distortion of grid current is 15.33%, hence goes against the IEEE 519–2014 standard. To decrease harmonics, a Shunt Active Power Filter (SAPF) is installed. After applying SAPF, the %THD is lowered to 5.60%, however it remains above the 5% threshold. As a result, a hybrid filter consisting of a SAPF and an LC filter is currently utilized to reduce the harmonics caused by SAPF alone. After applying the hybrid filter, the %THD equals 0.99%, indicating that the standard has been satisfied.
(a) Actual grid current (b) Grid current when SAPF is connected (c) Grid current when hybrid filter is connected.
%THD of (a) Grid current (b) Grid current when SAPF is connected (c) Grid current when hybrid filter is connected.
In this case, the 60-kW load is separated into 12 kW of linear and 48 kW of non-linear loads. The 48-kW non-linear load draws non-sinusoidal current, resulting in non-linear grid current. The actual grid current and with different filters applied, is illustrated in Fig. 52. An FFT analysis of grid current is performed to determine how much total harmonic distortion the 48-kW non-linear load puts into the system as in Fig. 53. The total harmonic distortion of grid current is 24.43%, which contradicts the IEEE 519–2014 standard. To reduce harmonics, a Shunt Active Power Filter (SAPF) is implemented. After using SAPF, the %THD is reduced to 11.24%, however it still exceeds the 5% requirement. As a result, a hybrid filter made up of a SAPF and an LC filter is now used to decrease the harmonics faced by the SAPF alone. After using the hybrid filter, the %THD is 2.85%, indicating that the criteria is now met.
(a) Actual grid current (b) Grid current when SAPF is connected (c) Grid current when hybrid filter is connected.
%THD of (a) Grid current (b) Grid current when SAPF is connected (c) Grid current when hybrid filter is connected.
The graph shown in Fig. 54, shows the variation in THD for three power sources, namely Solar PV, BESS, and the Grid, while supplying a non-linear load over a period of 24 h. This is because of two most prominent peaks existing at the non-linear load at around the 12th hour with a peak close to 45 kW and another near the 20th hour about 35 kW. Also, these peak load conditions of sources make a crucial bearing on the levels of the THD.
THD analysis without source allocation.
The grid usually shows the highest values of THD in general during the day and particularly at peak load hours. The distortion further increases steadily, reaching its maximum in the high-demand period of the grid, providing evidence of its inability to handle non-linear loads. In contrast, BESS has the lowest THD, maintaining minimum THD levels even at peak load. This shows how efficiently the BESS can provide clean power to non-linear loads. Solar PV operates at a medium scale, with its THD always below the grid and above BESS. The THD of all sources is drastically reduced during low-load periods, such as between the 12th and 14th hours.
At certain hours, there exist intersections of the THD levels for the different sources when their performances have seemed similar for a particular load level. For example, the early morning 2nd hour, the grid and Solar PV have almost the same THD value due to low demand for load. In the 14th hour, the levels of distortion in the grid and BESS are similar; such another intersection is observed about the 20th hour, wherein during the load peak, the THD of the grid and Solar PV seems almost to meet each other.
This analysis gives the inference that, during peak non-linear load conditions, priority should be given to the BESS for minimum THD, while Solar PV can be utilized effectively under moderate load conditions. As the grid has a higher THD, it should be reserved for periods of low demand. This source allocation strategy agrees with the usage of genetic algorithms for the dynamic selection of sources by taking real-time THD levels and variations in loads as an input to improve power quality in microgrid systems.
The graph illustrated in Fig. 55, represents THD levels of Solar PV, BESS, and the Grid over 24 h under the influence of non-linear loads. This will serve as a basis for comparison and for determining the best source to be allocated at each hour based on the lowest THD level. The analysis also considers the unavailability of Solar PV after the 19th hour, i.e., 7 PM and BESS is unavailable between 11 and 16th hour, i.e., 11 AM to 4 PM, as it is being charged during this time. The non-linear load profile peaks around 12th and 20th hour, which influences the THD levels of the sources considerably. It has been observed that, in all sources, the THD increases steadily with the increase in load during the early hours of the day.
THD analysis with source allocation.
During the first peak load period around the 12th hour, BESS is not available. At that moment, the Grid, having a little less THD compared to Solar PV, became the most favorable source. Beyond the 16th hour, again, BESS started to become available with continuous low THD hence becoming the most suitable source of the period for power allocation. From the 19th hour (7 PM) onwards, Solar PV is not available and there will be a need to choose between BESS and Grid. The second load peak occurs around the 20th hour. Regarding power quality, BESS exhibits the lowest THD compared to Grid. The lower the THD while the load decreases after the 21st hour, the better the performance of BESS and the Grid. The graph shows obvious periods where each source has the least THD and should guide the allocation strategy.
For example, the BESS selection provides the minimum THD during its availability, especially at late afternoon and evening hours. Otherwise, the Grid selection is done whenever Solar PV and BESS are not available, normally under peak load conditions. The higher the THD, the worse the power quality. This comparison underlines the importance of choosing the source with a minimum THD in order to have high-quality power in the microgrid systems with nonlinear loads.
The graph depicted in Fig. 56 compares the THD levels for three sources: Solar PV, Battery Energy Storage System (BESS), and the Grid, each interfaced through a Shunt Active Power Filter. In this work, a Shunt Active Power Filter has been deployed to damp harmonic distortions caused by highly nonlinear loads, thus making such loads compliant with the IEEE 519–2014 standard with its limit of 5% maximum total harmonic distortion.
THD analysis with SAPF only.
Accordingly, THD is significantly reduced from the precedent cases for all three sources with the implementation of the SAPF. Over the full 24 h, the best performance of BESS has a THD level way below the threshold at 5% even when under peak loading conditions. The result represents that BESS is therefore very effective in ensuring a fine performance in power quality by mitigating or eliminating harmonics with a proper combination with SAPF. However, Solar PV has also recorded better performance at the installation of a SAPF-increased from 6 to an average below 3 percent, and during peak-load hours-such as every 10th and 20th hour-it largely exceeds its THD, which amounts to more than 5%. Grid supplied with active filtering benefits while still exceeding THD at higher percentages compared to that emitted by either Solar PV or the BESS. Its own THD reaches beyond 10% during every peak period.
The results obtained depict that the Shunt Active Power Filter significantly enhances power quality for all sources. However, BESS, along with SAPF, performs the best in reducing harmonic distortion and maintaining THD levels within acceptable limits set by IEEE 519–2014. This shows that in microgrid systems with nonlinear loads, BESS is the best source when optimal power quality is to be achieved.
In Fig. 57, the graph illustrates the THD levels of Solar PV and the grid after the application of the Hybrid Filter, which consists of both SAPF and Passive Filter, applied selectively, to meet the IEEE 519–2014 standard. When the THD was less than 5%, just with the SAPF, Hybrid Filter was not used and therefore zero THD level is shown in the graph during those periods. In the case of Solar PV, %THD has a peculiar peak at the 9th and 10th hours of values exceeding 4.5%; it is where Hybrid Filter is used for mitigation of such distortions.
THD analysis with hybrid filter i.e. (SAPF + passive Filter).
Therefore, for the periods other than mentioned, the THD is kept to zero. That means for this period, SAPF is enough to maintain THD below its acceptable limit. Similarly, for the grid, there is a surge in the THD values between 8 to 13 h, having its peak about 3%, where the application of a Hybrid Filter can be seen. For other ranges, it shows zero harmonic distortions regarding the grid current. The effectiveness of SAPF comes into play because during these intervals, it worked effectively. The graph shows that the Hybrid Filter is used only in the case of high distortion caused by nonlinear loads. This ensures better quality of power at optimal usage of filtering resources. BESS is not used in this graph, as it maintained THD below 5% with SAPF alone in the previous case. This is the strategy of selective filtering to ensure efficient compliance with the standards of power quality.
Table 6 summarizes the extreme THD values seen in each operating mode and quantifies the effectiveness of SAPF and hybrid filters in driving all cases below the 5% IEEE 519 limit. Overall, BESS with SAPF achieves a 76% reduction in worst-case THD (16.01 to 2.62%), and grid-only with hybrid filtering delivers an 88% reduction (24.43 to 2.85%
Challenging issues related to climate change and the increasing demand for power presents a critical need for a transition in energy sources from conventional to renewable. The effective integration of renewable energy sources, including wind and PV, into existing power grids faces several challenges, particularly regarding grid stability and power quality under the influence of non-linear loads. This research carries out a comprehensive and deep-embedded study on the integration of a 100-kW three-phase grid-tied solar PV system with a Battery Energy Storage System (BESS) under non-linear loads. Four cases are analyzed to enhance grid stability and improve the energy management strategy. The simulation results illustrate that the THD levels of the BESS-supplied loads decrease significantly compared to other cases.
This study shows that changes in solar irradiance reflectively cause the sun’s variation or directly affect the occurrence of issues emanating from poor power quality in grid-connected solar photovoltaic (PV) systems. For instance, in the case of dropping solar irradiance with a 75% linear load and a 25% non-linear load, when the irradiance level drops from 1000 to 800 W/m², the %THD of grid current rises from 4.05% to 8%, and then THD starts to fluctuate at 7%. Meanwhile, with BESS-connected loads, the %THD remains at 3.68%. Thus, the quality of power from these solar photovoltaic systems is likely to be degraded—a source of grid stability concerns. The findings of this study further demonstrate the reduction of harmonics in loads operated by BESS. Employing load current as a reference in inverter control results in a lower THD level, indicating the need for robust control strategies to enhance power quality and reduce harmonic distortion levels. This research emphasizes the need to utilize BESS or the utility grid at low solar irradiance, especially for increased non-linear loads. The results show that BESS, with the proposed SAPF has the lowest %THD of total harmonic distortion compared to a stand-alone solar PV system or a utility grid supply.
Notably, the grid exhibits a high current THD of 12% even with SAPF, the highest among all sources. When a hybrid filter is applied, grid THD under maximum non-linear loading falls to 3.2%, outperforming the solar PV system’s 4.97% THD. These results define optimal source–filter pairings: BESS requires only SAPF; solar PV needs SAPF combined with enhanced inverter control; and grid supply benefits most from hybrid filtering to suppress higher-order harmonics. This framework advances sustainable energy integration and supports the clean-energy transition in alignment with UN SDG-7.
Looking ahead, several avenues can extend and deepen the impact of this work. First, real time Hardware in Loop (HIL) testing can validate and refine the proposed source-filter control strategies under realistic dynamics and communication latencies. Implementing the microgrid control framework on an HIL platform would enable direct integration with physical inverters, converters, and filters, facilitating rapid prototyping and robustness verification before field deployment.
Second, incorporating adaptive and learning based controllers, such as model predictive control (MPC) augmented with machine learning for load and generation forecasting could further enhance performance under highly variable renewable and load conditions. These intelligent algorithms would allow the system to predict upcoming distortion events and preemptively adjust source allocation or filter settings, reducing reliance on reactive filtering.
Finally, scaling the framework to multi-agent architectures could distribute decision-making across numerous converters and storage units, improving resilience against component failures and communication faults. Integrating cybersecurity measures and advanced grid-forming control techniques will be crucial for future microgrids that must operate reliably in the presence of both physical disturbances and cyber threats. Collectively, these developments will drive the transition toward more flexible, robust, and sustainable renewable-integrated power networks.
All data generated and analyzed during this study are included in this published article and its supplementary information files.
Renewable energy sources
Sustainable development goals
Battery Energy Storage System
Photovoltaic
Lithium-ion
Low voltage
Point of common coupling
Total harmonic distortion
Shunt Active Power Filter
Unified power quality conditioner
Finite set-model predictive control
Instantaneous active power from the photovoltaic array
DC-side power exchanged with the BESS
AC power output of the inverter
Power losses on the DC bus
Total load power (linear + non-linear)
Active power exchanged with the utility grid
α-β Frame currents after Clarke transform
α-β Frame voltages after Clarke transform
Instantaneous active and reactive power in α-β frame
Reference currents in the α–β frame for SAPF
Reference currents in the abc frame for SAPF
Total HARMONIC DISTORTION
Duty ratio for PV DC-DC converter (P&O MPPT)
Reference current for BESS charge/discharge
State of charge of the BESS
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The author extends the appreciation to the Deanship of Postgraduate Studies and Scientific Research at Majmaah University for funding this research work through the project number ER-2025-2005.
Abdullah Altamimi
Present address: Department of Electrical Engineering, College of Engineering, Majmaah University, 11952, Al-Majmaah, Saudi Arabia
Mohammed Alghassab
Present address: Department of Electrical and Computer Engineering, Shaqra University, 11911, Riyadh, Saudi Arabia
US-Pakistan Center for Advanced Studies in Energy (USPCAS-E), National University of Sciences and Technology (NUST), Islamabad, Pakistan
Muhammad Saleh Waseem Abbasi, Syed Ali Abbas Kazmi & Moatasim Billah
Engineering and Applied Science Research Center, Majmaah University, 11952, Al-Majmaah, Riyadh, Saudi Arabia
Abdullah Altamimi
Department of Electrical Engineering, Mirpur University of Science and Technology, Mirpur, AJK, 10250 , Pakistan
Zafar A. Khan
Department of Computer Systems Engineering Engineering, Mirpur University of Science and Technology, Mirpur, AJK, 10250, Pakistan
Zafar A. Khan
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SAAK, AA,MA and ZAK developed the concept and methodology of the study, MSWA and MB carried out the simulations. SAAK, AA and ZAK supervised the project and ZAK, AA and MA administered the project. All authors contributed in writing the main manuscript and reviewed the manuscript. The funding acquisition is done via AA.
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Saleh Waseem Abbasi, M., Kazmi, S.A.A., Billah, M. et al. Power quality optimization framework for three phase microgrids with grid tied solar PV and battery storage under nonlinear loads. Sci Rep 15, 42568 (2025). https://doi.org/10.1038/s41598-025-18954-3
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The solar industry’s readiness for an expected surge in end-of-life PV projects and equipment is the subject of a special report that leads issue 45 of PV Tech Power, out now.
As PV power plants built during the industry’s first growth spurt reach the end of their lifespans or are retired early, questions about how they are dismantled and the waste materials they generate are handled become increasingly critical. The figures are astonishing, with estimates suggesting the volume of end-of-life modules could reach tens of millions of tonnes in the next 20 years.
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Our cover report looks at how the industry should approach the issue, first by developing a set of best practices for decommissioning end-of-life projects. We also then examine some of the technologies and processes being developed in different parts of the world for recycling waste modules and recovering as much of the valuable materials they contain as possible.
As we approach the annual Intersolar Europe event in Munich, we also look at some of the challenges facing Europe’s PV industry. After several record years, the rate of growth in new installations has slowed slightly in the past year and looks set to remain cool for at least a couple more. We look at some of the structural challenges that must be overcome to underpin the next phase of the continent’s energy transition.
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A solar farm which has been likened to the size of Heathrow Airport has been planned for rural Cambridgeshire, to power up to 175,000 homes. However, two councils have raised concerns about the consultation. So what does this mean for the proposals?
Kingsway Solar Farm is set to cover more than 3,000 acres of farmland in East Cambridgeshire, but residents have told the BBC it could "envelope" the villages of Balsham, West Wratting, Weston Colville and Weston Green.
It has been classed as a Nationally Significant Infrastructure Project (NSIP), meaning Energy Secretary Ed Miliband will have the final say.
Kingsway said it had "carried out a robust and compliant multi-phase consultation programme, in accordance with the relevant legislation".
But in response to a Planning Inspectorate request, both East Cambridgeshire and South Cambridgeshire District Councils have raised concerns.
Stephen Kelly, planning director at South Cambridgeshire, said: "The council considers that the documentation relied upon for consultation… made it difficult to develop a clear and comprehensive understanding of the likely significant effects."
He went on to say that agendas and meeting notes were "often provided at very short notice or retrospectively", and that environmental and technical information "was not shared at key stages".
"Collectively, this approach has adversely impacted upon the council's ability to shape the development of the scheme, respond constructively to emerging evidence, and agree appropriate mitigation measures.
"Engagement has therefore been largely procedural and one-directional, rather than collaborative and iterative."
Meanwhile, in East Cambridgeshire planning committee papers, officials argued that Kingsway had not complied with part of the Planning Act, in that it "did not have regard to ECDC's concerns regarding the information provided in the consultation process, to allow consultees to make an informed opinion regarding the development".
Their planning meeting on Wednesday was told the implications of their response to the Planning Inspectorate could be that it would not accept the current submission of the plans, but it was acknowledged the chance of this was "fairly low".
Tony Day, from the Kingsway Solar Community Action group, said it was "unsurprising" the councils were concerned.
"We haven't seen any evidence of [Kingsway] taking our concerns into account whatsoever," he said.
Down a track road from the village of Balsham, Day told the BBC: "An area about the size of Heathrow Airport is going to be put under panels and we're seeing a large swathe of that area here.
"This can't be screened because it's the highest point in Cambridgeshire and you can see Ely Cathedral on a good day across the valley there, and from Ely Cathedral you would be able to see much of this development."
He said the group was "not opposed to solar energy at all", adding: "I've been teaching, researching it all my professional life. And there is a smaller solar farm near us and nobody is particularly bothered about that."
But he said: "You'll be covering 1,250 hectares of some of the best agricultural land in East Anglia with solar panels, so you'll be taking that out of food production."
Nick Acklam, a parish councillor in Reach, where the concern is about pylons as well as the impact on two Anglo Saxon dykes, says there has been a "fundamental failure to listen to or respond to our concerns".
"We raised concerns, we raised questions, we offered alternatives and we offered to participate in coming up with a better way of going forward," he said.
"We didn't even have an acknowledgement to our letter."
Speaking about the council comments about the consultation, he said: "I think it's a very significant moment.
"There's no denying that we are facing some real challenges, and there's no denying that people, broadly speaking, support a move away from carbon-based electricity.
"What concerns us, I think, is that developers are not consulting with local communities to take account of their concerns."
Asked if he thinks this intervention from the authorities could end the proposals, he said: "I really don't know.
"I think that's really one for the planning inspector to take a decision on, but I think, as things stand at the moment, there are some very serious concerns about the calibre and quality of this particular application."
Cambridgeshire County Council, another consultee, said it was "currently considering our own response, in line with planning legislation, which has been requested by the Planning Inspectorate".
Kingsway Solar declined an interview, but in a statement their head of NSIP projects, David Vernon, said: "The project represents a significant investment into the UK's energy infrastructure.
"If consented it will produce substantial amounts of reliable, clean, affordable, home-grown electricity which will help meet the growing needs of the country.
"Kingsway Solar is committed to bringing forward a high-quality scheme in alignment with the best practice in project development and design, and in complete compliance with all legislative and regulatory standards.
"A crucial part of the project's development has been the regular and detailed engagement held with local communities and stakeholders to ensure their inputs are reflected in the project."
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Ming Yang wanted to open the facility at Ardersier Port in the Highlands but the plan was blocked by the UK government.
The government says new regeneration body will deliver transport and services "alongside housing".
Scottish Borders Council is told it would be "a scandal" to develop anywhere near the historic sites.
East Cambridgeshire council is one of the last authorities to swap black bags for wheelie bins.
The link will run underground from Scotland to Anderby Creek in Lincolnshire, National Grid says.
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Iran Shock Jolts Asia and Europe to Speed Up Energy Transition  Bloomberg.com
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The UK's latest floating solar farm has been brought online at a site in Cheshire and is providing clean power to a neighbouring quarry. Scottish clean energy company Nova announced today the project…
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'Bottleneck to delivery': Report warns UK skills shortage could hobble Warm Homes Plan
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Project to provide neighbouring quarry Bathgate Silica Sand with clean power to help decarbonise its century old operations
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Solar energy covered around 14 percent of electricity consumption in Germany last year, up from 12 percent in 2023. How does that compare to Australia?
According to the Bundesverband Solarwirtschaft¹, the total output capacity of all solar power plants, large and small, exceeded 100 gigawatts (GW) when the calendar flipped over to 2025.
Given Germany isn’t as sunny as Australia, PV meeting 14 percent of electricity consumption in 2024 is pretty impressive. Last week, we reported that for the full year of 2024, rooftop solar in Australia’s NEM² accounted 12% of mains grid consumption. But what about with utility scale solar thrown in? According to Open Electricity, utility PV accounted for 7.1% of consumption last year – so the two together come to just over 19%.
BSW says “ground-level solar parks” (solar farms) were the biggest driver of PV growth in Germany, with a year-on-year increase of around 40 percent (6.3 GW – 32GW cumulative total). For rooftop commercial solar, it expects a growth increase of around 25 percent to 3.6GW (29GW cumulative total) last year.
But after several record years in a row, growth in home solar power system installations slowed in Germany. Compared to 2023, newly installed resident photovoltaic capacity (systems <30kW) fell by around an estimated 15 percent to 6.7 GW; bringing the total capacity installed to 38GW.
Overall, more than one million new solar power systems were registered in Germany in 2024, and installed photovoltaic capacity grew by around 10 percent compared to 2023.
As for Australia’s final figures for 2024, it’s still a bit soon to put a number on it.
Another aspect of PV that has been growing in Germany are “balcony” solar installations. These are small systems (maximum 800W capacity) feeding electricity directly into a power outlet to offset energy consumption within the home or building.
They’ve proven particularly popular in Germany, with newly installed capacity doubling in 2024 compared to the previous year (0.4 GW – cumulative total 0.7GW). If all those new systems were 800W (and they likely wouldn’t be), that works out to 375,000 installations in 2024.
The total installed capacity of approved balcony solar installations in Australia is 0kW.
Balcony solar appears a decent idea for households without control of their rooftop, for example, apartment dwellers.  So, given it *seems* like a no-brainer solution; why hasn’t it taken off here?
We don’t see these systems (legally) in Australia as back-feeding electricity into an electrical system creates several concerns. As an aside, such systems are pretty limited in what they’ll produce here. For a more in-depth look at these issues,  Kim’s article on balcony solar systems from last year has some good info and interesting discussion following it.
Germany has set at target for solar PV of 215 GW in 2030 – so, it has 5 years left to install another 100GW of capacity. It also has a target of 80 per cent of the country’s electricity sourced from renewables by the same year. According to Fraunhofer ISE, renewable energy’s share was 56 percent in 2024, compared to 55.3 percent in 2023.
The Australian Government has set a target of 82% renewable electricity nationally by 2030. In 2024, renewables accounted for 38.9% in the NEM and 38.8% in WA’s SWIS.
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Michael caught the solar power bug after purchasing components to cobble together a small off-grid PV system in 2008. He’s been reporting on Australian and international solar energy news ever since.
On “balcony solar”. In 2004 I created a 12 v “balcony” system which, rather than attempting to plug into the domestic circuit, I used a stand alone 240 v inverter (600w) , as well as 3 camping freezers (12v/24v/240v AC). Last year I replaced the old FLA 12 volt batteries with Lithiums recycled from an old electric maxi scooter, and upgraded 12 volt solar panels, under an MPPT controller. Operating on 240 v AC, the freezers draw 150 w total, but can now run overnight @12 v, and my house can go completely off-grid and have all storage, (24 volt SLA batteries with a Selectronic inverter/ charger for my rooftop) back at full strength before midday. Be interesting to see how it goes in winter. The hot summer has really chewed up the rooftop solar keeping the house cool.
I wonder if anyone can measure what is happening behind the meter instead of just what the networks see – with low FIT, how much self-consumption is going on and are we really measuring the right things?
The OpenElectricity website mentioned in the article includes rooftop solar that is both exported to the grid and also self consumed.
The AEMO dashboard on their website doesn’t include rooftop solar self-consumption so is less useful..
I doubt that that the rooftop solar figure includes self-consumed energy. My 6 year old Fronius inverter isn’t communicating with my smart meter to report what’s generated. To get that data, I had to have my own little meter installed as part of the installation, which I can then read from the inverter.
All of this is coming though.
Germany now is at about 65% RE compared to our 40 -50%. The following happed recently: During a prolonged “dunkelflaute” – no sun, no wind in Germany, they imported lots of energy from Scandinavia and doing so exported inflation to Scandinavia due to higher power prices there.
The Swedish energy minister with name Busch complained that as Germany decided to become nuclear free or baseload free, it did not have the baseload nor the Russian gas to get over the energy shortage.
One solution to this problem was the suggestion not to renew the submarine cables to the EU, which are due for replacement or to close them.
As we no longer have the local gas and are talking of building import terminals (!), we are in the same bed as Germany as our 20GW of coal is disappearing in 2038 and we need to have 16GW of gas running by then.
From; Tony Enright
Having worked in coal/gas fired generation for >50 years, I have become very concerned about future generation, considering the complete failure of successive governments (state and federal) to take responsibility after cashing in on the privatisation of government assets constructed from mid sixties to early nineties
Regarding the need for life extension of coal fired stations, it is unlikely that any will make 2038, as they have reluctant owners with who would prefer to be paid (by government) to shut down, rather than risk the displeasure of their shareholders. Surviving stations should be acquired by Fed Gov, to ensure their continued service.
Regarding gas, it would be criminal to consign our future to a dependance on imported gas rather than develop our own supplies. On gas generation, eastern states have less than 10 gigs, and no visible appetite to build more.
Neither major party is offering a plan that will work – I have been writing to politicians for years, with little response. The ongoing confusion created by having both state and federal governments responsible for the provision of energy in Australia will ensure that pollies always have somewhere to hide.
Sorry to be so pessimistic, but having been involved in the greatest power station building boom in Australian history, I greatly resent its destruction by political ignorance and indifference
Best Regards
Hi Tony,
I really appreciate your insight but don’t share your pessimism, other than the privatisation issue, everyone knows that’s been treasonous.
(Now please excuse me while I deploy a canned response usually reserved for the less informed and less civil comments section)
“Baseload” is electricity jargon which used to mean the minimum load you could justify running a steam engine.
Now it’s been hijacked by the coal industry, it roughly translates to “please remember when we were kings”
Things like off peak water heaters were introduced so that large thermal plants could be kept ticking along at a base rate. Stoking them up and down every day shortens the life of a boiler, so artificially cheap tariffs were introduced to -create- demand where it would otherwise never be.
Instead of shaping demand with limited availability tariffs designed to suit lumbering inefficient thermal generators, we now have real time pricing to incentivise use when energy is cheap… so SAPN has for years offered a “solar sponge” tariff at 25% normal rates compared to 125% for peak use.
There is genuine surplus in the system so the cheap rates are in the middle of the day now, and they’re cheaper than ever. So much so that feed in tariffs for consumers have fallen to almost zero.
That means people have incentive to change their behaviour, use their own energy, be more efficient. It’s actually well suited to large thermal batteries like hot water and ceramic heat banks.
Combined with demand response, where you’re effectively paid to curtail your use, and dynamic tariffs to incentivise batteries, “baseload” just disappears in a puff of smoke called negawatts.
https://jeromeaparis.substack.com/p/the-real-lesson-about-the-end-of?fbclid=IwAR2SLUYvlNVRNPeXlpHQuMv8hxrioJHXjuJAiljidvCr9218axMyESh0xd8
The linked article states that the share is 62%.
The 62.7 percent refers to net public electricity generation from renewable energy sources. According to Frauhofer:
“The share of renewable energy generated in Germany in the load, i.e. the electricity mix that comes out of the socket, was 56 percent compared to 55.3 percent in 2023.”
An interest article. However, it is interesting comparing the change in 2023 and 2024 generation over the NEM in GWh (and percentage change):
Coal(+1.75%) and Gas(+14.5%) increased by 3528GWh, solar(11.58%) and wind (2%) by 4951GWh.
The disappointing aspect is CO2 emissions increased 2.28% as NEM total power increased by 3.45%.
That 82% RE goal in 5 years mentioned seems impossible:
*Data centres alone will increase requirements by 8 to 15% over the 5 years, not to mention EV requirements.
*Four Wind farms were cancelled last year- Kingston Offshore, Barney’s Reef, Doughboy and WA Offshore.
*We are already curtailing a significant portion of our Solar production, hopefully Snowy2 175GWh will solve some of this, but curtailment will probably increase..
increase as more solar is produced.
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A research team from India has developed an agrivoltaic insect net house (AVINH) that combines solar power generation with protected cultivation of peppers.
The team constructed two types of AVINH structures, then conducted microclimate, statistical, and economic analyses, as well as a land equivalent ratio (LER) determination.
“AVINH offers several environmental advantages, including lowering carbon emissions, reducing the need for pesticides, and decreasing soil erosion and evaporation while providing farmers with a guaranteed income,” the research team said. “To assess this technology under practical circumstances, the study was carried out at a research farm.”
The research farm is located in the Indian state of Gujarat. The two AVINHs both incorporated 12 solar panels rated at 150 W, with one AVINH featuring an open roof and the other a closed roof.
The covered-roof AVINH had insect-net material stretched across the gaps between the PV modules, while the open-roof AVINH left these gaps uncovered. The rest of the structure was identical, with the net house measuring 8.04 m in length, 4.10 m in width and 3 m in height, with a white insect net made of 40 meshes stretched over it. An additional S3 design of conventional open-field cultivation was used as a control.
Under each structure, three pepper plots were planted, each with a different treatment. The first plot (T1) consisted of raised beds covered with mulch, the second (T2) combined raised beds, mulch and biofertilizers and the third (T3) used a soilless growing medium made of vermicompost and cocopeat together with biofertilizers. In each case, the researchers measured air temperature, relative humidity, light intensity and solar radiation using HOBO data loggers and solar-tracking instruments. Measurements were taken between December and March.
The scientists said that over the course of the experiment, the facility generated 1,058.30 kWh of energy, which they said was more than conventional power plants and standard agrivoltaic systems
“The reason for this higher energy conversion is that plant evapotranspiration cooled the solar panels on the back side,” they explained. “The capacity factor associated with this energy conversion system exhibits a minimum fluctuation, ranging from a minimum value of 19.42% to a maximum of 21.15% throughout the experimental period.”
The team tested the LER, which compares the combined food and electricity output of an agrivoltaic system to that of separate crop and solar production, with values above 1 indicating more efficient land use. The highest LER was achieved under the covered AVINH with T2, with a score of 2.55. T3 under the covered AVINH came second, with 2.28, while T1 under the covered AVINH achieved 2.26. Under open-roof conditions, T1, T2, and T3 had LERs of 1.82, 1.68, and 1.67 respectively.
“The system’s reasonable payback period of eight years underscores its economic viability,” the group had concluded. “To further optimize and expand the application of AVINH systems, future research should focus on identifying ideal shade-tolerant and shade-resilient crop varieties. Investigations into diverse AVINH designs and materials are crucial for fine-tuning microclimate conditions to enhance crop growth.”
The team’s results appear in the research paper Agricultural intensification with Agrivoltaic insect net house systems: Delving into techno-economic feasibility in soilless media, published in Energy Nexus.
Scientists from India’s Vellore Institute of Technology and Junagadh Agricultural University participated in the research.
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A new report by CareEdge projects that India’s solar module manufacturing capacity will reach around 250 GW by FY30, supported by nearly 90 GW of cell manufacturing capacity and more than 30 GW of ingot and wafer manufacturing capacity.
The report highlights that India’s solar PV manufacturing ecosystem is gradually moving towards backward integration, which is expected to reduce import dependence, strengthen supply-chain resilience and support long-term self-reliance.
Several large players such as Tata Power, Adani Solar, Waaree and other domestic manufacturers have announced plans to set up ingot and wafer manufacturing capacities in phases.
FY25 marked an important structural milestone with the commissioning of India’s first ingot and wafer manufacturing facility, with an initial capacity of 2 GW. The country is also at the cusp of commencing domestic polysilicon production, with major fully integrated manufacturing facilities expected to come online between FY26 and FY28.
Backward integration gains momentum
Despite the progress in solar PV manufacturing, domestic cell manufacturing currently meets only about 25–30% of demand, resulting in a sizeable gap in the upstream value chain. Consequently, India remains dependent on imports, particularly from China, for solar cells. This exposes the sector to supply-chain disruptions, price volatility and trade-related risks.
CareEdge noted that Chinese manufacturers continue to benefit from deep vertical integration across polysilicon, ingot, wafer, cell and module, which enables them to maintain lower cost structures. To address this gap, Indian manufacturers are increasingly investing in domestic cell manufacturing. Further, the applicability of ALMM-II, which mandates the use of domestically manufactured cells and modules, is expected to make integrated cell-to-module manufacturing critical for policy compliance, cost stability and participation in utility-scale and government-supported projects.
“India’s integrated solar manufacturing build-out is anticipated to require cumulative capex of more than INR 80,000 crore by FY30 across modules, cells and ingot-wafer capacity. However, the actual requirement may vary depending on global market conditions, equipment costs, technology shifts and supply chain dynamics” stated Nitu Singh, Associate Director, Care Analytics and Advisory Pvt Ltd.
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Construction has commenced on Fortescue’s 440MW Solomon Airport solar farm, which will become Western Australia’s largest solar development once complete.
Located in the Pilbara, the project will deliver around one-third of the total solar capacity required for Fortescue to achieve its Real Zero Target. Construction is expected to be completed in 2028, with approximately 671,000 solar panels to be installed during the build.
The project follows construction of the 190MW Cloudbreak solar farm, which is around two-thirds complete.
Fortescue Metals and Operations Chief Executive Officer, Dino Otranto, said: “Across the Pilbara, we’re using the region’s sun and wind to generate green power for our sites.
“We’re building the solar and wind farms, connecting them through our high-voltage transmission network and backing them with battery storage to provide 24/7 firm power.
“Importantly, each successive solar project is being delivered more efficiently than the last. As technology improves and we gain scale, our installed capital intensity continues to come down – strengthening the economics of replacing diesel and gas with renewable energy.”
A proposed 644MW solar farm at Turner River is anticipated to commence construction later this year. Once operational, the Solomon, Cloudbreak and Turner River projects – together with the existing 100MW North Star Junction solar farm – will deliver around 1.3GW of solar capacity. This is equivalent to powering around half a million Australian homes each year.
Construction is also underway on the 133MW Nullagine Wind Farm, further diversifying Fortescue’s renewable energy mix.
Together, these projects represent one of the largest renewable energy deployments by any heavy industry company in Australia.
Through Pilbara Energy Connect, Fortescue has already constructed more than 480 kilometres of high-voltage transmission lines across the Pilbara. Once complete, the network will extend to more than 620 kilometres, physically linking Fortescue’s energy assets to its operations and rail network.
Copyright 2026, Fortescue Ltd

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04 Jun, 2026 By Lee Kenny
Solar and marine energy systems firm Nova has switched on the UK’s newest floating solar farm for one of the largest producers of high-quality industrial silica sand.
The successful “powering up” of the 400kW floating photovoltaic (FPV) array took place on North Arclid Lake, an artificial lake located at the Arclid Quarry in Cheshire.
It comprises 650 floating solar panels and “marks a significant milestone” for Bathgate Silica Sand’s drive to decarbonise its century-old quarry operations and reduce its energy bills, said a statement from Nova.
It was developed in partnership with engineering and technical services firm RSK, from initial feasibility, through design, securing consents, installation and operation.
The approach allowed Bathgate Silica Sand to have the energy asset installed without any interruption to its business.
“The FPV array – with a footprint equivalent to two Olympic swimming pools – is generating clean electricity for Bathgate Silica Sand, reducing energy costs and giving the company greater control over its energy security,” the Nova statement said.
“Nova delivered the project, from start to completion, in just six months. The project leverages Nova’s years of experience as an internationally recognised leader in marine energy.”

Nova crews work on the installation of the project.

Nova crews work on the installation of the project.
Nova CEO Simon Forrest said: “Achieving first power at the Cheshire quarry is a significant milestone and a testament to our team.
“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.”
He added: “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.”
Bathgate Silica Sand is one of the largest producers of high-quality industrial sand in the UK, and managing director David Robinson said the floating solar farm represents a “significant moment” for the 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,” he added.
 
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The government of Queensland in Australia has opened a call for proposals for new solar and wind projects, battery storage systems, and broader support for the state’s northwest power system under the AUD 200 million ($144 million) North West Energy Fund (NWEF).
The NWEF was established as part of the state government’s changes to the proposed CopperString transmission project, which aims to connect north and northwest Queensland with the National Electricity Market (NEM) via a new link between Townsville and Mount Isa.
The fund, managed by state-owned Queensland Investment Corporation (QIC), is designed to support the delivery of new energy generation and storage solutions in partnership with the private sector across Mt Isa, Cloncurry, Julia Creek and Richmond while the CopperString transmission project progresses.
QIC said the AUD 200 million fund will consider proposals ranging from new solar and wind projects, gas and battery storage systems, as well as broader support for the North West Power System.
Alongside progressing such solutions, the QIC said work will also be undertaken to inform planning for the CopperString Western Link between Hughenden and Mount Isa.
The call for proposals follows QIC’s market sounding with developers, generators, electricity distributors, suppliers, customers and local governments in and around Mount Isa, Cloncurry, Julia Creek and Richmond.
QIC head of global infrastructure Ross Israel said the market sounding had provided key insights that will allow QIC to fast-track opportunities to connect private capital with priority projects in the northwest.  
“Supporting near-term investable projects that deliver reliable, affordable and sustainable energy will help unlock economic development opportunities in the northwest,” he said.
“A critical piece of this work will be undertaking the work required to define the end-state system to optimise the opportunity set in the region.”
“QIC’s role is to turn the objectives of the Queensland Energy Roadmap into investable projects that deliver reliable, affordable and sustainable energy and the North West Energy Fund presents a clear pathway for QIC to partner on near-term opportunities.
QIC has released investment guidelines highlighting key criteria, including a need for proposals to deliver benefits from, or reach commercial operations by 2030; and demonstrate an improved cost of delivered power in the northwest and/or surrounding regions.
Queensland Energy Minister David Janetzki said the NWEF builds on the state government’s commitment to deliver the CopperString project and progress economic development in the northwest.
“This fund enables us to pass on the benefits of CopperString to communities west of Hughenden while advancing the accelerated delivery of the project’s Eastern Link,” he said. 
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Maine is the leading state for community solar deployment per capita according to the latest Institute for Local Self Reliance data. ILSR’s tracker ranks states by community solar capacity per resident, showing how program design directly impacts market development and growth potential.
The top ten states, according to ILSR’s per-capita ranking, are Maine, Minnesota, New York, Massachusetts, the District of Columbia, Colorado, Illinois, Maryland, Rhode Island, and New Jersey.
Community solar allows customers to subscribe to a portion of an off-site solar project and receive bill credits for the electricity generated. The model is especially important for renters, multifamily residents, low- and moderate-income households, and homeowners whose roofs are not suitable for solar.
ILSR tracks community solar capacity in states with formal programs that allow non-utility ownership. Its latest tracker notes that 19 states and Washington, D.C., allow community solar, though the organization’s capacity tracking is limited to states with accessible, regularly maintained success data.
#1 – Maine
Maine ranks first by a wide margin, with roughly 700 watts of community solar per person, according to ILSR. The organization said community solar accounted for 53% of all existing solar capacity in the state at the end of 2025.
Maine’s market grew under its net energy billing rules, created in 2011 and expanded in 2019, but recent policy shifts, like LD 1777, signal upcoming changes that industry professionals should monitor.
#2 – Minnesota
Minnesota remains one of the foundational U.S. community solar markets. The state’s program launched in late 2014, and Minnesota has long been an early example of a market that scaled by avoiding hard caps on programs and using a compensation structure that made projects financially viable.
Minnesota was the national leader in community solar for years before being overtaken by New York in total capacity and, more recently, by Maine on a per-capita basis. Even so, its ranking shows the durability of the state’s early market design.
#3 – New York
New York is the largest community solar market by total tracked capacity. The state passed its first community solar legislation in 2015, and its Community Distributed Generation program has since become one of the most active in the country.
ILSR said New York added 112 MW of community solar capacity in the most recent quarter, representing 4% growth. The state was also among the year-over-year growth leaders in 2025, with community solar capacity up 28%. At the end of 2025, community solar represented 42% of New York’s existing solar capacity.
#4 – Massachusetts
Unlike some other leading markets, Massachusetts governs community solar through its broader solar incentive framework rather than a standalone community solar law.
The latest version of the Solar Massachusetts Renewable Target program, SMART 3.0, took effect in September 2025. ILSR notes that SMART 3.0 set a 900 MW size cap for 2025, and new community solar projects will likely apply under the updated rules because they offer more favorable incentives than SMART 2.0.
#5 – District of Columbia
The District of Columbia ranks fifth. ILSR notes that D.C. reports community solar figures annually, rather than quarterly. At the end of 2025, community solar represented 20% of existing solar capacity in the District, placing it alongside Maine, New York, Minnesota, and Massachusetts as one of the few tracked markets where community solar makes up a double-digit share of total solar capacity.
#6 – Colorado
Colorado was one of the earliest adopters of community solar policy, establishing its program through HB 1342 in 2010. ILSR notes that the original program design was slow to gain traction, but updates in 2016 and 2019 improved the market.
Colorado’s current market has largely operated through Xcel Energy’s Solar*Rewards Community program. A new inclusive community solar program established by SB 24-207 is scheduled to begin in 2026, with initial capacity allocations of 50 MW for Xcel Energy and 3.5 MW for Black Hills Energy.
#7 – Illinois
Illinois passed its first community solar legislation in 2016 and now administers community solar through programs such as Illinois Shines and Illinois Solar for All.
ILSR notes that Illinois uses long-term contracts between utilities and approved vendors to purchase energy and renewable energy credits. Contract terms vary by program type, with Illinois Shines offering 15-year terms for Community-Driven Community Solar projects and 20-year terms for Traditional Community Solar and Public School projects.
#8 – Maryland
Maryland established its community solar pilot program in 2017 and divided capacity across investor-owned utility territories. The state also built low- and moderate-income access into the program design, including a dedicated share of capacity for lower-income households.
In 2025, Maryland was one of the fastest-growing tracked community solar markets, with ILSR reporting 30% year-over-year growth.
#9 – Rhode Island
In Rhode Island, state lawmakers expanded remote distributed generation rules in 2016, creating multiple structures for shared renewable generation. Community net-metering systems operate like traditional community solar programs, allowing utility customers to subscribe to a portion of a facility and receive virtual net-metering bill credits based on their share of the project’s output.
Rhode Island’s ranking shows how adjusting community solar capacity for population can lift smaller states higher on the list.
#10 – New Jersey
New Jersey passed its first community solar legislation in 2018, launched a pilot program, and made the program permanent in 2023.
New legislation could drive a significant expansion of the market. In 2025, New Jersey enacted legislation calling for an additional 3 GW of community solar capacity, bringing the total available program capacity to 3.25 GW. The state also requires 51% of each community solar project to be committed to low- and moderate-income participants, and subscribers must be guaranteed savings of at least 15% of the value of bill credits.
New Jersey was the fastest-growing state in ILSR’s most recent quarterly update, increasing community solar capacity by 16%, or 35 MW.
Taken together, the per-capita rankings show that community solar leadership is not limited to the largest solar states. Maine, Minnesota, and D.C. rank ahead of several larger markets because community solar represents a larger share of their local solar portfolios.
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From pv magazine Australia
A proposed 100%-First Nations-owned solar and battery power station in Western Australia, the Aalga Goorlil Sun Turtle Djarindjin Community Power Project (DCPP), has received planning approval from the Western Australia Regional Development Assessment Panel (RDAP).
The project will be built on the Dampier Peninsula in the Kimberley region, about 170 kilometers north of Broome, 2,400 km north of Perth, and 1,600 km southwest of Darwin. The AUD 12 million ($8.6 million) project is expected to meet 80% of the energy needs of the Djarindjin and Lombadina communities.
The remaining 20% of electricity demand will be supplied by an upgraded diesel generator operated by state-owned utility Horizon Power.
The project will feature 3,408 solar panels arranged in the shape of the Djarindjin community’s official symbol. The installation will include a 3.25 MW battery energy storage system (BESS) connected to the Djarindjin-Lombadina microgrid.
The project aims to reduce the communities’ reliance on fossil fuels, lower energy costs, and support broader climate action efforts.
Djarindjin Aboriginal Corporation Chief Executive Officer Nathan McIvor said community ownership is central to the project. “The time has passed where communities rely on a broken system, and we out at Djarindjin don’t believe the system works for us,” McIvor said.
In a statement, the First Nations Clean Energy Network (FNCEN) said the RDAP agreed that “the essential infrastructure development supports community self-sufficiency, and broader benefits including training and employment.”
Revenue generated by the project will support the Djarindjin Aboriginal Corporation’s efforts to expand local employment and training opportunities, while helping to deliver and subsidize essential services.
McIvor said the Aalga Goorlil “Sun Turtle” project would support the community’s economic independence, diversify revenue streams, and build local capacity to construct, operate, and maintain critical infrastructure across the Dampier Peninsula.
He said the project is an example of self-determination in action.
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Every solar project begins with a number: expected annual energy yield (PVOUT). It feeds into nearly every major project decision: plant design, equipment selection, CAPEX assumptions, debt sizing, investor returns, and long-term contractual commitments.
But PVOUT is never a single fixed truth. Behind it sits a range of uncertainty. And just as the estimated PV yield means different things to different stakeholders in the solar project, the same applies to uncertainty and challenges it represents.
The same uncertainty figure can therefore create three very different conversations:

Engineers use yield estimates to guide key design decisions, from tracker configuration and row spacing to DC/AC ratio, inverter loading, clipping strategy, and loss assumptions. For them, uncertainty is not just a reporting metric. It’s a practical design constraint.
When uncertainty is low and well understood, they can compare design options with confidence and justify choices that improve performance or reduce costs. When uncertainty is high or poorly defined, optimization becomes harder to defend, and conservative decisions often feel safer.
This can lead either to overdesign, with unnecessary capacity, margins, or equipment, or to under-optimization, where the model misses site-specific effects such as soiling, shading, bifacial albedo, or clipping dynamics.


Investors do not invest in one production number. They invest in a range of possible outcomes. While P50 represents the expected case, investment committees also focus on downside scenarios. They need to know whether the project still works if production is lower, CAPEX rises, financing tightens, or market prices weaken.
This is why the gap between P50 and P90 matters. A project may show an attractive P50 return, but if uncertainty is high, the P90 return can be much weaker. The wider the gap, the more fragile the investment case becomes.
Reducing uncertainty may not increase expected yield, but it can improve confidence in downside returns – often the case that matters most in investment decisions.

Lenders view yield uncertainty through one main question: can the project service its debt under conservative assumptions?
This is usually assessed through metrics such as Debt Service Coverage Ratio (DSCR), which shows whether project cash flow is sufficient to cover debt payments. Banks often use conservative production cases, such as P90, but they do not simply apply an annual uncertainty discount across the full project life.
That approach can be too blunt. Mechanically reducing production every year can weaken DSCR, loan-life coverage, and equity returns, making a project look less bankable than it really is. Instead, lenders usually manage uncertainty through financing structure: debt sizing, DSCR thresholds, reserves, covenants, dividend restrictions, guarantees, or sponsor support.

Simply reporting uncertainty is rarely enough. Here is why actively reducing uncertainty is more effective.
Let’s look at an example of the effects of “doing nothing” (scenario A) and “reducing uncertainty” (scenario B) on a simplified 10 MW PV project. The expected specific production is 1,500 kWh/kWp. That gives the project a P50 annual production of 15,000 MWh. On paper, the project looks the same in both scenarios.
The difference is how uncertainty is treated.
In the “do nothing” case, the project relies on standard inputs, limited validation, averaged data such as TMY, hourly simulations, and simplified loss assumptions. The result is a total PV yield uncertainty of around ±10%. This places P90 annual production at about 13,500 MWh. This project would reach the lender’s required DSCR of 1.25, but only with 70% debt and a P90 RoE of about 4.9%.
In the “reduce uncertainty” case, the same project uses better irradiance data, longer historical time series, more detailed modelling, higher temporal resolution, and more realistic loss assumptions. The P50 annual production remains 15,000 MWh, but uncertainty falls to around ±8%, raising P90 annual production to about 13,800 MWh. In the same illustrative example, this improves DSCR headroom, allows debt to increase to 72%, reduces required equity, and raises P90 RoE to about 5.4%.
Nothing physical has changed. The power plant size is the same. The expected production is the same. The energy price is the same.
What changes is confidence. That confidence has financial value.
Fig. 2. Reducing PV yield uncertainty is beneficial for each stakeholder’s objective.
This is one of the most important points in the uncertainty discussion. Reducing uncertainty does not necessarily mean increasing the expected yield. In many cases, the P50 remains unchanged. The improvement appears in the conservative case.
When uncertainty falls, the gap between P50 and P90 narrows. That means the project’s downside production estimate improves, even if the expected production stays the same.
For engineers, this can justify more precise design decisions.
For investors, it can improve the resilience of downside returns.
For lenders, it can create more comfort around debt service.
This is why uncertainty reduction should not be seen only as a technical refinement. It can influence leverage, equity requirement, capital efficiency, and the overall competitiveness of a project.

Reducing uncertainty means improving the parts of a project you can control. For instance, interannual variability cannot be eradicated, but uncertainty in irradiance inputs and simulation assumptions can often decrease with relatively low friction. That usually happens when using validated, high-quality solar datasets over a long period of time, moving beyond typical-year averages where possible, and incorporating modelling approaches that better reflect real plant behaviour and losses. In regions where the situation is more complex, adding site measurements and local validation can further tighten confidence.
Below are things to consider if you want to take action in reducing uncertainty.
●     Validate component datasheets and ensure model parameters match what will be installed.
●     Use proven, validated solar radiation datasets (long-term satellite-based time series + ground validation where available).
●     Use higher temporal resolution when relevant (sub-hourly) to capture clipping, peaks, and thermal dynamics.
●     Use long-history time series to understand interannual variability (it’s not enough to rely on TMY).
●     Replace fixed “rules of thumb” losses with physics-based models where possible (soiling, albedo, temperature).
●     Model optical losses with advanced methods where complexity warrants it (e.g., ray-tracing in challenging layouts).
PV yield uncertainty is often owned by technical teams, but its consequences are shared by everyone. It can influence investors through downside confidence, engineers through design conservatism and banks through bankable energy assumptions. Reducing uncertainty can change how defensible the investment case becomes, how precisely engineers can optimize, and how efficiently lenders can finance a project.
At the same time, uncertainty reduction should be proportionate to the project and market context. While deeper data, modelling, and validation work can be justified on utility-scale projects, the same investment may not always be worthwhile for smaller assets or in markets where energy prices, curtailment, or interconnection risks dominate the business case.
The choice is not between uncertainty and certainty. No PV project can eliminate uncertainty completely. The real choice is between accepting uncertainty passively or reducing what can be reduced before it becomes expensive.
AUTHOR

Pablo Caballero, Engineer & Technical Writer at Solargis
Pablo is an industrial engineer with extensive experience in the renewable energy and software development sectors. 
We are India’s leading B2B media house, reporting full-time on solar energy, wind, battery storage, solar inverters, and electric vehicle (EV)
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Setting a New Benchmark in Shading Performance: Jinko Solar’s Tiger Neo 3 Earns TÜV Rheinland Class A+ Anti Shading Certification  SolarQuarter
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The European Commission has unveiled a strategic roadmap for digitalization and artificial intelligence (AI) in energy, as part of a wider tech sovereignty package.
The roadmap sets out how AI and other digital solutions can ensure the sustainable integration of digital infrastructure in the bloc’s energy system, while also making the system more efficient.
In a statement available on its website, the commission says the roadmap will tackle cybersecurity concerns by undertaking a risk assessment of solar and wind installations.
“Solar and wind power generation digital infrastructure are emerging as a priority cybersecurity concern, with high risks that include the manipulation or prevention of electricity production, unauthorized access to operational data, the infiltration of key supply chain actors and the possibility to trigger remote blackouts,” the commission said.
“To respond to these risks, the commission is undertaking a risk assessment of solar and wind installations in the EU, including cybersecurity risk assessment, and has restricted the use of EU funds for projects involving inverters from high-risk suppliers.”
It adds that it will also review the energy security of supply framework, which may include new measures for better identification and management of cybersecurity risks in critical energy devices.
“Strengthening cybersecurity and safeguarding critical infrastructure across the whole energy system must remain central as digitalization comes with exposure to hybrid and cyber threats,” commented Dries Acke, Deputy CEO of SolarPower Europe.
The strategic roadmap also plans to accelerate the deployment of digital and AI solutions in Europe’s electricity infrastructure, support a faster rollout of smart meters and build sovereign AI models for the energy sector, trained on European data and developed by European companies, that help to simplify the exchange of cross-border energy data.
It also commits to ensuring that data centres are integrated into the bloc’s energy system in a sustainable and transparent manner.
Acke added that as AI adoption accelerates and data centre capacity expands, Europe must ensure this growth strengthens, rather than strains, the energy system. 
“Data centres should therefore be properly integrated through smarter planning, greater flexibility solutions and closer coordination between all stakeholders,” he said. “The combination of solar and battery storage provides a prime opportunity for swift and sustainable data centre integration.”
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Fire crews battled a three-alarm fire at a home in Franklin, Massachusetts, Wednesday evening.
The fire broke out in the basement of a home on Elm Street, eventually spreading to the first and second floors and then the attic.
Fire officials said the fire was heavily involved when crews first arrived, and there was difficulty putting it out because of how far the flames had spread.
Crews were called out of the home due to an impinged propane tank. Solar panels on the roof of the home also made battling the blaze more difficult.
“By the time we were ready to, to really go with heavy water, the fire had really taken the whole house at that point,” Franklin Battalion Fire Chief Keith Darling said.
Three people were inside the home at the time of the fire, but all residents were able to evacuate safely.
Video from a witness at the scene showed flames and thick black smoke shooting from the top of the home.
“It’s just crazy, we’ve been living here – I’ve been here for five years now, and I’ve never seen anything up close like this before,” neighbor Candace Devens said.
Several neighboring towns, including Attleboro, Foxborough, Milford and Hopkinton, responded to put out the blaze.
No one was hurt in the blaze.
The cause of the fire is under investigation.
Hearst Television participates in various affiliate marketing programs, which means we may get paid commissions on editorially chosen products purchased through our links to retailer sites.

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Your source for AEC industry trends, innovations, and best practices
A Swiss startup, Zurich Soft Robotics, has devised a photovoltaic façade that tracks and moves with the sun. The company calls Solskin the first commercially available intelligent climate-adaptive building envelope.
Developed by architects and robotics researchers at Swiss research university ETH Zurich, the Solskin hardware comprises adjustable photovoltaic modules that serve a dual purpose: producing renewable electricity while also shading the interior.
The PV modules are mounted on a modular structure that includes all the wiring. The dynamic, lightweight system can be used on both new buildings and façade renovations. Through testing, the team also has confirmed the system’s extreme weather resistance.
When placed in front of a building’s windows, Solskin can reduce building energy consumption by up to 80%, according to ETH research. The solar-tracking modules produce up to 40% more electricity than comparable façade systems. In some cases, such as a south-facing glazed office space in Zurich, the Solskin system can cover the building’s entire energy consumption.
Zurich Soft Robotics’ recent innovation, Solskin AI, makes the system even smarter by leveraging predictive self-learning algorithms. With Solskin AI, the system can control the position of the solar modules in real time—achieving optimal energy efficiency and ensuring the comfort of occupants behind the Solskin facades. The use of AI helps address user preferences, weather conditions, and energy consumption.
Solskin’s moving elements constantly adapt to the environment, leading to increased comfort and reduced energy consumption—which will become increasingly critical with climate change.
All Solskin systems will have continuous AI updates, ensuring the energy-efficient, intelligent building envelopes are always up to date, with a focus on longevity and sustainability.

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York Space Systems Closes Acquisition of Solestial, U.S.-Sourced Space Solar Capability  Yahoo Finance
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Solar Energy
Scatec announced a significant advancement for the sustainability of solar energy in Brazil. During Environment Week, the company reported that it aims to achieve 100% recycling of materials present in damaged solar panels used in the construction of the Rio Urucuia plant in Minas Gerais.
The project, which has an installed capacity of 142.31 MWp and about 201,000 photovoltaic modules, reinforces the potential of solar panel recycling as an environmental and economic tool. According to estimates from the photovoltaic energy sector, every R$ 1 invested in this process can generate a return of R$ 3.18, strengthening the circular economy and reducing waste disposal.
Besides financial gains, the initiative prepares the Brazilian market for a future where millions of solar energy equipment will need to be replaced at the end of their useful life.
Now it’s law: energy distributors can be penalized for hiding data about solar energy in MS; The measure increases market transparency, reduces barriers for consumers, and accelerates the expansion of distributed generation in the state.
How the “solar cat” became a billion-dollar threat to the Brazilian electrical system and put ANEEL on high alert after the explosion of photovoltaic energy, clandestine frauds, and the growing risk of network collapse
Solar energy covered rooftops and deserts, but now it’s preparing a mountain of old glass: up to 78 million tons of photovoltaic panels could become waste by 2050 as the world races to recycle the shiny skin of the energy transition.
Company launches floating solar platform at sea to test bifacial panels and generate renewable energy in coastal waters
The Rio Urucuia plant marks a new stage in Scatec‘s environmental strategy. The company intends to fully reuse the materials present in modules damaged during transport, storage, or installation.
Until recently, solar panel recycling processes focused mainly on the recovery of glass and metals. Now, the company is advancing towards the reuse of more complex materials, including plastics and rubbers.
The company’s Community Relations Coordinator, Ledjane Oliveira, who also has a background in Materials Engineering, highlights that this evolution significantly increases the efficiency of waste reuse generated by the photovoltaic energy industry.
The concept of circular economy is gaining strength in various industry segments, especially those related to the energy transition.
In practice, the proposal consists of reducing waste and keeping materials in use for as long as possible. Instead of simply discarding waste, it returns to the production chain as raw material for new products.
In the solar energy sector, this model offers several advantages:
As photovoltaic energy grows in Brazil, the adoption of the circular economy tends to become increasingly strategic to ensure long-term sustainability.
The result achieved in Rio Urucuia was built from previous experiences.
In 2025, Scatec initiated a pioneering project involving the recycling of approximately 4,700 modules from the solar plants of Mendubim, in Rio Grande do Norte, and Quixeré, in Ceará.
At that time, the company reached a recycling rate of about 85%. The knowledge gained from these operations allowed for process improvement and increased material recovery.
According to Ledjane Oliveira, although the number of recycled panels is still relatively small, the knowledge acquired today will be crucial when the first large-scale solar energy plants begin to replace equipment on a large scale in the coming decades.
The Brazilian photovoltaic energy market continues to expand its share in the national electricity matrix. New plants and distributed systems are installed every year in homes, businesses, and rural properties.
Although the panels have a long lifespan, generally over 25 years, there will come a time when many of these pieces of equipment will need to be replaced.
This scenario will require a robust solar panel recycling structure, capable of handling large volumes of materials.
Therefore, initiatives like those of Scatec are considered important to prepare the production chain and prevent future solar energy waste from becoming an environmental problem.
The results obtained by the company at the Mendubim and Quixeré plants help to gauge the environmental potential of the activity.
According to the released data, the operation allowed:
To carry out the logistics operation, 11 trucks were used to transport the equipment from Rio Grande do Norte to Minas Gerais, where the materials were processed.
Another data highlighted by the company indicates that for every 39 cubic meters of photovoltaic sector waste correctly sent for recycling, approximately 13 tons of CO₂ equivalent are prevented from being emitted into the atmosphere.
One of the main benefits of solar panel recycling is the recovery of materials with significant commercial value.
According to information presented by Scatec, the highest concentration of lead in the modules is located in the metal alloy responsible for the connection between the photovoltaic cells.
This composition contains approximately:
After separating these components, the materials are sent to specialized foundries. This reduces environmental risks and allows them to return to the production cycle.
The recovered lead can be used again in the manufacture of connectors or automotive batteries. Meanwhile, copper and silver have wide industrial applications, adding value to the circular economy process.
In addition to environmental gains, recycling presents a significant economic potential.
According to estimates cited by Scatec, the photovoltaic energy sector estimates that each R$ 1 invested in recycling can generate a return of R$ 3.18.
This result helps change the perception that waste reuse represents only an operational cost. In practice, it can become a source of revenue through the recovery of reusable materials.
The scenario also opens up opportunities for new businesses related to logistics, industrial processing, and commercialization of raw materials from solar panel recycling.
The strategy adopted by the company is aligned with Scatec‘s global sustainability commitments.
According to the company, the goal is to achieve net zero carbon emissions by 2040. In this context, expanding recycling processes plays an important role in reducing environmental impacts throughout the entire production chain.
The initiative also demonstrates that the growth of solar energy can occur increasingly integrated with the principles of the circular economy, combining clean energy generation with efficient resource reuse.
The advancement announced by Scatec shows that solar panel recycling is moving from a complementary activity to a strategic role within the sector.
The ability to reuse 100% of the materials present in damaged modules demonstrates that the circular economy can generate environmental and financial benefits simultaneously. The recovery of glass, metals, plastics, rubbers, and high-value components reduces waste, prevents emissions, and creates new business opportunities.
With the continuous expansion of photovoltaic energy in Brazil, initiatives like this tend to gain increasing relevance. Besides strengthening the sustainability of solar energy, they help build a more efficient production chain, prepared for the challenges of the coming decades and capable of transforming waste into valuable resources.
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Avangrid has completed construction of the 166 MWdc/120 MWac Tower Solar project in Morrow County, Oregon and has connected the facility to the regional electricity grid. Commercial operations for the project are expected to begin in summer 2026. The project features more than 250,000 solar panels assembled by SEG Solar at its Houston manufacturing facility.
Once fully commissioned, the project will supply clean electricity to Portland General Electric through its Green Future Impact program and support QTS operations in the region. The project created approximately 200 construction jobs and is expected to contribute around $20 million in PILOT and property tax payments to the local community.
In May 2026, Avangrid signed a long-term power purchase agreement (PPA) with Puget Sound Energy (PSE) for the Big Horn I wind project located in Klickitat County, Washington. The project will have a nameplate capacity of 199.5 MW, enough to supply electricity to around 70,000 homes annually. The project, developed by Avangrid in 2006, is expected to commence commercial operations in 2028 following its redevelopment.
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UK-headquartered company ConFlow’s iLamps are fitted with a 600 W circular solar panel, two lithium-ion batteries and a Nvidia computer processing chip. Everything is remotely monitored via an app, and all the system hardware is housed inside the lamppost.
The idea is to leverage the streetlamps to create a large virtual power plant (VPP) network capable of absorbing the demand placed on the world’s electricity grids by big data centers.
VPP network
Deployment is already happening in Nigeria, the UK and in the United States, and Fitzpatrick told pv magazine that ConFlow is targeting half a million streetlamp units in the pipeline by next year. But the streetlamp isn’t really the product.
“We’re building a platform for AI for power, comms and data. The iLamp is just the node that we put all of that through,” Fitzpatrick explained.
“A lot of people say we can’t compete with a large-scale data center by putting GPUs into streetlights. That’s true. But we don’t have to cool ours so we’re already more efficient and the compute is more efficient, and it costs us and the environment less.”
He added that the streetlamp VPP network provides a sort of intermediary between the larger data centers doing higher compute learning tasks. “The iLamp brings the data center closer to your phone for lower demand tasks like asking ChatGPT a question,” said Fitzpatrick. This is known as inference and the latency is less than what’s required for learning-based tasks.
Business model
Local authorities and governments pay for the compute-per-hour and for the power the lamps provide. At the moment, ConFlow charges 49c per compute hour, which Fitzpatrick claimed is “really cheap for inference compute for AI.” Each iLamp generates about $4,500 per annum.
“We also charge a little bit for the power because we want to create green utilities in every location,” the CEO added. “If there’s 50,000 iLamps in a state, we create a green utility and we sell the power to the government at a green kilowatt hour of power but at a very low rate. The green utility is far more beneficial to the end user than it is to us… it gives them loads of benefits like carbon credits.”
ConFlow is in talks with local authorities to deploy the lamps in the UK, as well as in Kazakhstan, Sri Lanka, India, Kenya, Nigeria, and the United States. Licensing is available in most countries already. The biggest problem is the red tape involved, and Fitzpatrick said the company has gravitated towards early deployment in countries with less bureaucratic restrictions, like Nigeria.
Intelligence services
The type of inference-based intelligence data the lamps provide depends on the user’s requirements. The state picks what services they want ranging from weather data, autonomous vehicle connections, traffic data, building security, sports performance, and even gunshot detection, all delivered via an AI powered camera inside the lamp at head height.
“From speed spotting to gunshot prevention to sports, we’re doing 80 applications like that, because we can teach the camera literally anything. We’re working with a local drama department to help us teach the camera,” said Fitzpatrick.
Panic buttons can also be installed in the iLamps to alert emergency services. Fitzpatrick is not too concerned about the possibility of people stealing computer chips or solar panels from the lamps. As he said, the solar is built into the lamp and anyone hoping to steal it would need an angle grinder and to disable the camera. If the GPU is removed from the lamp, it is automatically fried and therefore useless. “Nobody can steal 50,000 lamps”, said Fitzpatrick.
He also defended the surveillance aspect of the service, claiming ConFlow provides a service that governments want to buy.

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De Soto solar farm project’s status remains hazy three years after zoning approval  The Business Journals
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OSHKOSH (NBC 26) — A planned solar farm in Waushara County is drawing concern from residents and farmers who worry about falling property values and potential land contamination.
Plainfield resident Nick Derks said the 1,000-acre installation, which spans the towns of Oasis, Hancock, Plainfield, and Deerfield, is a significant issue for the community.
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Derks is urging neighbors to attend an upcoming public meeting to make their voices heard.
“Now we have a meeting coming up next Tuesday, and I would just like everybody in the Western Waushara County area to be there if they’re at all concerned about the future of the land,” Derks said.
The meeting will be held at the Plainfield Municipal Building on West Clark Street in Plainfield.
The project has several participating local family farmers. According to Ranger Power, the company behind the project, solar energy provides a stable revenue source to help farmers hedge against challenges including an unpredictable crop market and high fuel costs.
Not all farmers support the project, however. Waushara farmer Kurt Kamin raised concerns about pollutants potentially contaminating the land and affecting its long-term viability.
“The canning companies have stricter and stricter rules. There’s an issue and they get that stuff. If something ends up in the groundwater, how many acres does that affect? You know, is this ground ever going to be viable again? I don’t think it is,” Kamin said.
Dawn Break Solar, the developer involved in the project, states that its panels do not contain PFAS or GenX, two dangerous chemicals, and emphasizes solar energy’s positive impact on reducing greenhouse gas emissions. The company also notes that solar panels do not use significant amounts of water during operation, keeping water available for farming and other activities.
Dawn Break Solar is scheduled to begin construction in early 2027, with the project becoming operational in 2028. The project is privately funded and will not use taxpayer dollars.
This story was reported on-air by a journalist and has been converted to this platform with the assistance of AI. Our editorial team verifies all reporting on all platforms for fairness and accuracy.
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From pv magazine Australia
New data from global energy consultancy Rystad Energy shows that all Australian large-scale solar power plants generated 1,730 GWh of clean energy last month, up 21% from the 1,435 GWh produced in April 2025 with Queensland home to three of the top five best-performing utility PV assets for the month.
The 204 MW Edenvale Solar Park, co-owned by Japanese companies Eneos and Sojitz, was ranked Australia’s top-performing big PV facility for the month with Rystad Senior Analyst David Dixon noting the power plant had delivered an average AC capacity factor (CF) of 33.1% for the month.
Greek energy company Metka’s 82 MW Moura Solar Farm ranked second for the month with the central Queensland facility delivering an average capacity factor of 32.8 %.
Stage 2 of Acen Australia’s 400 MW Stubbo solar project in New South Wales (NSW) was ranked third with a capacity factor of 32.6 % while the first stage of that project was listed in fifth place. Neoen’s 460 MW Western Downs solar farm in Queensland was ranked fourth.

Dixon said all Australian utility-scale PV and wind assets generated 4.7 TWh of clean energy last month, up 24% from 3.8 TWh in April 2025.
At a state level Queensland was in top spot for utility solar and wind generation at 1,256 GWh with 678 GWh from utility PV and 578 GWh from wind.
The top wind assets for the month were the Granville Harbor and Cattle Hill wind farms in Tasmania with the Kennedy Energy wind farm in Queensland third.
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April 01 – August 31, 2026
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The solar industry stands at a critical juncture. As billions of panels installed over the past two decades approach the end of their lifespans, the sector faces the unprecedented challenge of what to do with the tens of millions of tons of decommissioned photovoltaic modules expected to flood the market in the coming years, with volumes projected to reach staggering levels by 2050.
According to Sonia Dunlop, CEO of the Global Solar Council (GSC), the message is clear: the time to address solar recycling is now.
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“Solar recycling has to be dealt with today, for the solar panels being installed now,” Dunlop emphasises, in response to questions from PV Tech Premium. “Due to our nature as a low-cost form of electronics with an extremely long lifespan—sometimes 30+ years—recycling has to be paid for at the point of purchase rather than at the point of disposal.”
This disconnect between installation and decommissioning timelines creates a fundamental challenge. The funds needed to recycle panels decades from now must be collected and carefully invested today, requiring government mandates and industry delivery mechanisms that can span generations.
While some regions have made significant progress, the global recycling infrastructure remains woefully unprepared for the coming wave of decommissioned panels. The European Union has led the charge, mandating solar recycling since 2012, and currently holds over 70% of the global recycling market, according to Dunlop. However, as solar deployment accelerates worldwide, this concentration presents a problem.
“Solar deployment is accelerating, and we need to diversify the recycling industry beyond Europe,” Dunlop notes.
Some of that diversification has begun. Beyond Europe, China, Australia, Japan and South Africa are notable for having national-level policies to regulate PV waste, while a few US states have also instituted PV waste regulations of varying degrees of stringency. At the same time, extensive research efforts are underway, and new innovations are emerging for recovering the most valuable materials from PV modules.
Yet these initiatives remain scattered across a global industry that installed record-breaking capacity in recent years, and nowhere near the necessary industrial capacity is in place to handle the likely waste volumes that will emerge, or to maximise the economic value of the recoverable materials PV modules contain.
Central to addressing the recycling challenge is establishing the right financial mechanisms. Dunlop strongly advocates for what the industry calls an “advanced recycling fee”—a pay-as-you-buy approach that embeds the nominal cost of recycling into the upfront purchase price.
“It protects the consumer from inflated higher costs when the panel reaches the end of its life,” she explains. This model has proven particularly effective in Europe over the past decade, but much of the world has yet to implement similar measures.
The approach faces complications, however. Solar panels are often classified alongside electronic and electrical equipment such as laptops and mobile phones—a categorisation that Dunlop considers a misfit. Panels have much longer lifespans and typically much lower purchase prices per kilogram than consumer electronics. Moreover, many panels installed 25 years ago were manufactured by companies that no longer exist, casualties of the cutthroat nature of solar manufacturing.
“What we really need is for governments to design solar PV-specific—and indeed battery storage-specific—recycling schemes,” Dunlop argues, highlighting the need for tailored regulatory frameworks that account for the unique characteristics of solar technology.
Creating a circular economy for solar panels requires coordinated action from both public and private sectors. Dunlop is clear that if the industry wants to roll out solar at speed and scale, a “both-and approach” is essential.
Major original equipment manufacturers have already begun investing heavily in recycling, either through proprietary technology or partnerships with specialist firms. In the US, Canadian Solar and Qcells have agreements with SOLARCYCLE, for example, while PV Cycle serves numerous companies globally. These private sector initiatives demonstrate industry recognition of the challenge ahead.
However, private investment alone cannot solve the problem. Government mandates and public sector support remain crucial for establishing the comprehensive, well-organised and well-financed global recycling system the industry requires.
The ultimate goal is ambitious but achievable: developing a fully circular lifecycle for photovoltaic equipment. Dunlop cites estimates she has seen suggesting that solar PV and battery energy storage systems could become entirely circular industries, requiring no new mining by 2040. The potential is clear—one old PV module can theoretically produce enough material for ten new ones, Dunlop points out.
“Whether we actually manage to deliver this depends on a well-organised and well-financed global recycling system, which has to be government-mandated,” she states, emphasising the critical role of policy in realising this vision.
Several obstacles currently prevent the industry from achieving circularity at scale. Cost remains a significant factor. While prices have declined, solar recycling can still appear more expensive than landfill disposal in some countries, partly because recovered raw materials are not being resold for their true value. However, innovative companies are developing more efficient recycling technologies daily, and costs are projected to continue falling significantly.
Regulatory gaps present another challenge. In many countries, solar recycling regulations are still catching up to deployment. Australia, Japan, China and India are beginning to examine how they can address the challenge at scale, but comprehensive frameworks are still under development.
The nascent state of the recycling industry itself poses difficulties. A sector striving to catch up to the scale and speed of well-established and rapidly growing solar manufacturing faces inherent growing pains.
The EU’s Waste Electrical and Electronic Equipment (WEEE) Directive stands as a clear blueprint for effective policy. Any region stands to benefit from a more robust solar recycling industry and regulatory environment, but those already delivering deployment at scale have the most immediate need.
Beyond policy, the GSC is working to facilitate practical collaboration across the value chain. The organisation has served as a link between members and specialist recyclers such as PV Cycle, which offers collective and tailor-made waste management and legal compliance services globally. In Nigeria, CleanCyclers represents an innovative approach to expanding PV recycling services in emerging markets, Dunlop says.
Dunlop emphasises the importance of due diligence at both ends of the product lifecycle. The industry is working to engage buyers to “check before you buy” and developers to “check before you throw”. Investors and local authorities are already asking questions about recycling before investing in and permitting utility-scale sites.
Looking ahead, the GSC is considering making recycling part of the Solar Stewardship Initiative buyers’ guidelines. Such integration would formalise recycling considerations into investment and procurement decisions across the industry.
The GSC has discussed the recycling challenge with the International Renewable Energy Agency (IRENA) and hopes to eventually create a dedicated Recycling Workstream. International standards and harmonisation will play crucial roles in scaling solutions globally.
As the solar industry continues its remarkable growth trajectory, the recycling challenge looms larger with each passing year. The panels being installed today will need proper end-of-life management decades from now, making current action imperative. With the right combination of government mandates, industry investment, technological innovation and international cooperation, the vision of a fully circular solar industry can move from aspiration to reality.
The question is not whether the industry can rise to meet this challenge, but whether it will act with sufficient speed and coordination to build the infrastructure needed before the coming decommissioning wave breaks.
The latest issue of our journal PV Tech Power leads with a special report exploring the PV end-of-life challenge, from project decommissioning through to recycling and the pathway towards a circular PV supply chain. To read our coverage in full, click here (subscription required).

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Water contractors can expect to pay between 1% to 3% more for the energy it takes to bring supplies down the state through California’s largest project thanks to just one renewable energy project that came online recently in Kern County – the Pastoria Solar Project.
And that’s just the beginning.
When the Department of Water Resources (DWR) brings on enough renewable energy projects to fully power the State Water Project (SWP), contractors can expect their costs to increase another 10% to 20%, according to a presentation at the May 20 California Water Commission meeting by DWR Manager of Power Operations Jorge Quintero.
Quintero said 45% of the power needed for the SWP is currently coming from renewables, including the project’s own hydro electricity. The department has contracted for renewable projects to provide another 11% of its power needs. 
That means DWR has to find renewable energy projects for the remaining 44% of its power needs.
Quintero estimated it would cost between $35 million and $40 million a year to fill that remaining 44% need, increasing energy costs to contractors by another 10% to 20%.
And it has to happen fast per Senate Bill 1203, which mandates state agencies achieve net-zero greenhouse gas emissions by 2035 – just nine years from now. 
“I’d be lying if I said this wasn’t a big concern,” said Jonathan Young, energy manager for the State Water Contractors association. “We didn’t oppose the 2035 mandate but we did voice our concerns.”
Because DWR is using long-term power purchase agreements to lock in how much it pays for the power, that does give contractors a greater degree of cost certainty, Young said.
“Anything that adds certainty, adds value,” Young said. 
DWR declined to say how much it’s paying for power produced by the 100-megawatt Pastoria Solar Project, which came online in late April. The state keeps that information under wraps for three years in order not to undermine future contract negotiations, according to a DWR spokesperson.
The spokesperson would only say that DWR’s 20-year purchase agreement for Pastoria’s solar power is “competitive,” but more than $1 per megawatt hour, as had been reported in other media.
Time and money will be tight to meet SB 1203’s mandates.
The Pastoria Solar Project, DWR’s largest solar investment so far, took four or five years from the first request-for-proposal to flipping the switch, according to John Yarbrough, Deputy Director of the SWP.
The department needs another 400 megawatts – or four more Pastoria facilities – to fill its remaining power needs. 
In the meantime, DWR and contractors are trying to control power demands, and costs, by operating the SWP in a more flexible manner depending on other needs on the grid. And many contractors are installing their own solar facilities, Young said during the May 20 California Water Commission meeting.
He told SJV Water that power is just one of many cost concerns for contractors including combatting invasive golden mussels and subsidence (land sinking) beneath the California Aqueduct.
“And we didn’t even get into SGMA,” he said referring to the Sustainable Groundwater Management Act, which mandates farmers bring over pumped aquifers into balance by 2040.
Those, and other, costs were cited recently as several Kern County agricultural water districts have significantly reduced their participation levels in funding the planning and pre-construction phase of the Delta Conveyance Project, a tunnel that would bring Sacramento River water beneath the ecologically sensitive Sacramento-San Joaquin Delta to be exported south.
The SWP is the state’s largest single electricity consumer, using between 2.5 million and 9.5 million megawatt hours a year, depending on how much water it’s moving. It moves water more than 700 miles from northern to southern California, hoisting it 2,882 feet up and over the Tehachapi mountains in Kern County.
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Falling costs and greater demand led to a 40% uplift in battery additions in 2025, according to the latest IEA data. This was driven by major acceleration in utility scale deployment, which accounted for 87 GW of the 108 GW added in 2025.
Around 24 GW of utility-scale BESS additions in 2025 were co-located with renewables, on par with the previous year. This means share of capacity for co-located renewables fell just below 30%, which the IEA attributed to market reforms in China in early 2025 which removed broad co-location mandates.
Key growth markets identified by the IEA included Australia, where battery capacity additions surged to nearly 8 GW, almost nine times higher than the previous year.
Utility-scale installations in Australia were up from less than 1 GW in 2024 to around 4.2 GW in 2025, while behind-the-meter additions increased from roughly 0.2 GW to about 3.4 GW, supported by state- and federal-level incentives. It means battery storage now accounts for around 18% of installed dispatchable capacity in Australia, ahead of China (7%), the United States (5%) and Europe (4%).
China continues to dominate BESS additions in absolute terms. Just over 63 GW of new battery capacity was added in China in 2025, one-third more than in 2024. Utility-scale scale installations accounted for 55 GW of the total, with the IEA recording about 8 GW of behind-the-meter additions.
In the United States, 19 GW of battery storage was split across more than 16 GW of utility-scale BESS and nearly 3 GW behind the meter.
Utility-scale BESS may have accounted for lion’s share of new capacity additions but global behind-the-meter installations accelerated also accelerated in 2025. The IEA noted markets with high retail electricity prices and supportive policy frameworks saw increased deployment.
The dramatic fall in costs for battery storage – down by more than 90% between 2010 and 2025 – has supported deployment growth according to the IEA, while the growing proportion of renewables in the global energy generation mix has also increased demand.
IEA noted that early battery projects were concentrated in “lucrative but relatively shallow ancillary service markets” but business models for BESS have changed. Energy arbitrage – storing energy when prices are low, to sell when they are high – has become the dominant application. The IEA estimates the share of projects engaged in this kind of energy shifting has increased from around 40% in 2015 to more than 90% in 2025.
Battery storage durations have also risen as demand for energy shifting has grown. The average duration of projects commissioned rose to three houses in 2025, up from around two hours in 2023.
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India Posts Record 44.6 GW Solar Addition In FY26 Despite Rising Oversupply Risks  BW Businessworld
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Florida-based solar-as-a-subscription startup Terra Energy has officially launched its new TerraOne plan, a 36-month agreement for homeowners in the CenterPoint and deregulated service areas of greater Houston, Texas. 
Under the plan, Terra Energy installs a rooftop solar installation and 40 kWh battery at the homeowner’s premises, and sells the electricity to the homeowner over the subscription term. 
In its announcement of the program, Terra said the cost to the homeowner for the subscription can be as low as $0.06/kWh before delivery charges, based on usage, system design, and program eligibility.
The low prices are a result of Terra’s Texas business model, backed by the company’s first virtual power plant (VPP). Similar to VPP programs from other Texas solar and battery providers, Terra Energy will aggregate the batteries it installs at customer homes to provide energy, capacity, and ancillary services to grid operators, creating a source of revenue in addition to subscription fees.
In addition to income from its VPP operations, the company says its unique business model and vertical integration of sales, warehousing and operations allows it to keep overhead costs low.
At the end of the initial term, the homeowner can choose to continue the subscription or cancel. Terra Energy is counting that most of its customers will choose the former, and the company says it has data to back that up.
In April, Terra CEO and founder Jaime Martinez told pv magazine USA the company had retained 98% of its customers beyond the 3-year mark in Mexico, its original market. 
At the time, subscriptions for Terra’s first customers in Florida were just beginning to reach 36 months, and Martinez said that 100% of those customers retained their subscription to the company’s service. 
Since that time, the company has been testing its Texas offering in a pilot program, which has now become TerraOne. 
“We’re proud to be launching our decentralized power plant solution in Texas to help make it simple for Houston homeowners to lower their electricity cost while keeping the lights always on,” said Martinez in a statement. “For two decades, going solar meant needing to write a big check or take out a 20-plus-year loan. We’re lowering the barriers to entry for homeowners with TerraOne’s short-term subscription.”
Also in April, Martinez said his company planned to offer its service in additional Texas regions and expected to expand to California sometime later in the year, but the company has not made any further announcements about those plans.
Homeowners interested in learning more about the company’s Texas offering can visit www.terraenergy.io/texas.
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Winning with AI
Facing rapid growth, the company built AI capabilities to balance scale, efficiency, and risk.
Rapid growth and rising operational complexity pushed TCL Photovoltaic Technology (TCL PV Tech), a new energy company within TCL Corporation, to embrace artificial intelligence. Between 2022 and 2025, the company’s revenue surged from roughly RMB 600 million to RMB 20 billion. At the same time, highly dispersed projects, more intricate processes, and shifting policy environments heightened the demand for efficiency, consistency, and risk management. 
AI as a foundational capability—not just a tech initiative—answered TCL PV Tech’s question: How can we reduce costs, improve efficiency, and ensure high-quality scale growth? With Bain’s guidance, the company zeroed in on a set of high-impact AI use cases at the intersection of transformation potential and capability maturity. 
auditing process cost reduction
Rather than focus on standalone pilots, TCL PV Tech prioritized solving pain points—those critical yet constrained processes that would hinder sustainable growth. In collaboration with Bain, the organization introduced:
•    Intelligent inspection, which reduced reliance on human judgment for processes like site survey and final grid connection
•    Real-time analysis and forecasting of power markets to boost efficiency and accuracy
•    AI-powered recognition to continuously monitor power stations and flag potential faults early, improving the speed and accuracy of maintenance responses
TCL PV Tech’s dedicated AI service group continues to scale AI across the business, embedding it in core capabilities to balance efficiency gains with risk control as the company grows. But beyond the tactical wins, Bain helped the company adopt an end-to-end transformation mindset. Faced with a highly uncertain business climate, the company built a sustained capability through process and organizational change. In that context, the organization’s AI-enabled transformation was not a one-time rollout but a continuous journey of iteration and refinement.
First, major, immediate pain points need to be addressed. Second, tangible results must be [achieved]. Visible success helps more colleagues recognize the real benefits AI brings and motivates them to go further.
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Sungrow Renewables, a division of Chinese inverter and storage system manufacturer Sungrow, has launched its first solar module at on June 1 at its 2026 smart technology conference in Shanghai.
Dubbed Pulson, the new product is described as a smart PV module designed to function as an active terminal within photovoltaic power plants rather than as a passive power-generating component.
The panel is based on what Sungrow Renewables calls a “5S” architecture comprising self-diagnosis, self-rapid shutdown (RSD), self-cleaning, self-cooling and self-logging functions. It also integrates power electronics, advanced materials and artificial intelligence algorithms to improve safety, energy yield and lifecycle management in PV plants.
According to Sungrow Renewables, the self-diagnosis function relies on a module control box with embedded chips that collect voltage, current, temperature and other operating data from individual modules. Moreover, AI-based analysis enables module-level fault detection and localization, allowing operators to move beyond plant-level monitoring.
The self-RSD function provides both module-level and system-level protection, which means faulty modules can be isolated to limit the impact on the rest of a string. In emergency situations, the system can also reduce site-wide DC voltage to a human-safe level within 25 seconds, according to the manufacturer.
The module also incorporates self-cleaning and self-cooling technologies. Sungrow said nano-hydrophilic surface treatment and its proprietary “Silver Ant” cooling technology help reduce power losses caused by dust accumulation and elevated operating temperatures. The company claimsthe two features can increase energy generation by about 6%.
The self-logging function assigns each module a digital record, or “electronic passport,” containing carbon footprint data, health status, operating logs and other lifecycle information. Sungrow Renewables said the feature is intended to support operation and maintenance activities, asset evaluation and long-term plant management.
During the event, TÜV SÜD issued what Sungrow Renewables described as the industry’s first certificate for a high-efficiency smart PV module. The company also said Pulson is the first product to achieve the L2 “active safety intelligence” level under the smart module classification framework proposed in the new white paper. The framework categorizes smart PV modules into four levels, ranging from L1 sensing and optimization capabilities to L4 autonomous decision-making.
The module will initially be deployed in PV plants developed by Sungrow Renewables. Chairman Zhang Xucheng said the product emerged from a development cycle involving “power plant application, pain-point identification, technology accumulation, hardware iteration and power plant feedback.”
More technical details about the new product were not revealed.
Sungrow Renewables is the renewable energy project development arm of Sungrow. The company develops, invests in, designs, builds and operates PV, wind, energy storage and other renewable energy projects. It said it has developed and constructed a cumulative 59 GW of renewable energy projects across more than 17 countries and regions.

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