From pv magazine 10/23

Farmers are under pressure. Cost pressure, environmental pressure, regulatory pressure. There are obvious reasons to diversify income streams but there’s also every reason to avoid additional risk.

For most farms, agrivoltaics means fixed installations, often on rooftops – well-established technology with predictable costs and returns. But things are changing. Pilot schemes for farm-based solar projects are popping up across the European countryside, testing the mounting industry’s latest innovations in the process.

Land demand

Cormac Gilligan, a director at analyst S&P Global with a focus on solar and energy storage, told pv magazine that mounting system development is in lockstep with land scarcity. In mature solar markets, the best utility-scale sites have been snapped up, fueling demand for cost-efficient ways to install solar on more rugged terrain.

Gilligan said most of the tracking systems the solar mounting industry has brought to market recently have been designed with undulating terrain in mind. That enables trackers to be installed at higher gradients, reducing the need for costly soil levelling on undulating sites. From the land developer’s perspective, cutting capital expenditure is a win. In the agricultural sector, things get much more complex.

Making the business case for farm-based PV is not a simple calculation. There’s a balance to be struck between farming yield and energy output. That’s why projects that experiment with different mounting systems in different locations and with different crops are so important. Gilligan’s colleague Joe Steveni, a research analyst at S&P Global, said that these schemes will help to paint a more general picture of what works well in
different agricultural settings.

“If you have a successful pilot in northern France, you’ll have a good understanding for the south of France,” Steveni said. “It will spread.”

In the field

In North Rhine-Westphalia, Germany, a new pilot scheme promises to provide data on how solar installations affect crop yield and quality while investigating potential auxiliary benefits ranging from improved irrigation to a reduced need for crop protection. By the end of this year, three different types of mounting system will be installed at the site. Research will start at the beginning of 2024 and is set to run for at least five years.

Located on seven hectares of recultivated land at the Garzweiler opencast mine, near Bedburg, the pilot scheme is a partnership between energy giant RWE and the national research institute Forschungszentrum Jülich, with financial support provided by the state government. The demonstration plant will have a peak generation capacity of 3.2 MW.

Berries on the farm will grow beneath PV modules elevated on a high structure created by Zimmerman PV-Stahlbau. It is predicted that the steel company’s mounting system will be a good fit for berry cultivation as crops including raspberries and blueberries can tolerate shade.

Vertical-aligned solar mounting systems from Next2Sun are also being installed at the site, spaced at intervals wide enough to allow harvesting machinery between the module rows. On the tracker front, Schletter Group’s 2P Tracker System is being installed in rows that both follow the sun and deliver additional benefits.

Alongside investigating crop suitability and cultivation methods, research will focus on how the solar installations can be optimized so that standard components can be used as much as possible. RWE said this would reduce the levelized cost of energy and should lead to an “acceleration of the market ramp-up of agri-PV.”

On the agricultural side, there is a lot to learn. Matthias Meier, project leader for agrivoltaic activity at Forschungszentrum Jülich, told pv magazine that the scheme could provide the kind of insights that farmers need to invest with confidence.

“Farmers are asking about the costs of these kinds of systems,” he said. “They are used to making quite big investments with their machinery, and a lot also have rooftop PV. They know how to deal with that but agri-PV is an uncertain technology for them. I cannot say ‘if you put it on your sugar beet field you can harvest as much as without agri-PV’, or ‘you can calculate this kind of factor.’ This we cannot say at the moment and this is the most uncertain point.”

Proven tech

There may be unknowns for farmers but there’s real certainty coming from solar mounting system suppliers. Christian Salzender, the head of project sales at Schletter Group, said pilot schemes are not really trials for his business, so much as demonstrations.

“We know the system works but we also want to show it to our clients in small sample installations,” he said.

Salzender said trackers offer more efficiency and therefore leave more space for farming and growing. Schletter’s system can also move to 60 degrees from the horizontal, creating space for harvesting machines and the potential to dump snow from modules during the winter.

Operation and maintenance costs have also been improved in the latest generation of tracker systems, Salzender added. “Mechanical failures are as likely as in cars,” said the Schletter representative. “The overall components are well proven throughout different industries.”

From pv magazine Germany

Germany installed 919 MW of new PV capacity in September, according to the latest figures from the Federal Network Agency (Bundesnetzagentur). This compares to 1,056 MW in August and 750 MW in September 2022.

In the first nine months of this year, developers connected 10.72 GW of solar to the grid, compared to 5.6 GW in the same period a year earlier.

This means that the German government's goal of achieving a newly installed capacity of 9 GW for this year has already been exceeded. With a view to the goal of a cumulative installed capacity of 215 GW by 2030, the monthly increase – viewed linearly – would have to be 1,578 megawatts, as determined by the Federal Network Agency. This value has not been reached in any month so far this year.

The country's cumulative solar capacity surpassed 77.67 GW at the end of September.

In September, the combined capacity of rooftop systems supported with feed-in tariffs or market premiums totaled 666 MW. This is also the lowest value since February and a significant decrease compared to previous months when there were more than 800 MW in this segment – with the peak value of almost 937 MW having been reached in June.

Reduced moisture in the Amazon delivered clear skies and increased irradiance across the tropics of South America. Solar assets in the region saw 110-120% of average monthly irradiance through September.

A strong and slow-moving storm early in the month lessened irradiance in southern Brazil, but the rest of mid-latitude South America saw mostly normal irradiance, according to data collected by Solcast, a DNV company, via the Solcast API. The Altiplano Plateau saw the highest irradiance for the whole continent. This is in line with historical averages, as the area records some of the highest irradiance levels in the world.

In September the tropics saw higher irradiance than usual. This was due to clearer skies caused by the current drought in the Amazon. The northeastern part of the Amazon has been dry since mid-July, resulting in reduced moisture in the rainforest and less evapotranspiration. This is a major source of moisture fuelling cloud formation over rainforest regions.

The region saw regular cumuliform clouds typical of tropical regions, but not the large storms and rainfall events that are typical of the start of the wet season in September. The rivers in the Amazon are reported to be at their lowest level in over a century as there has been a lack of rainfall and ensuing dry conditions in recent months. This has been exacerbated by warm conditions, as South America recorded the warmest September extending from heatwaves.

The Brazilian southern states of Rio Grande de Sul and Santa Catarina saw reduced irradiance. It recorded 10-20% below September averages and is due to an unusually strong extra-tropical cyclone. The storm moved onshore from the Atlantic in early September, and it’s slow-moving nature meant the irradiance impacts were more focussed and intense. Most of the remainder of mid-latitude South America saw much more moderate irradiance at or slightly below the long-term average.

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

From pv magazine Australia

While 2023 is still trailing 2021 for small-scale solar installations, the difference is now only 150 MW, or 7%, according to data from Sunwiz. In 2021, the fourth quarter was the most tumultuous three-month period. On the other hand, elevated lead levels and a spike in Google searches suggests that the fourth quarter of this year will contend for the strongest period in 2023.

“I think there’s already a good deal of momentum backed in and that we are going to see elevated levels [of sales],” Warwick Johnston, managing director of Sunwiz, tells pv magazine Australia. “I suspect we are going to have a strong October, so we’re up for a record year.”

Lead volumes this September were up 78% compared to the number of quote requests in September 2021, Sunwiz has found. Many customers are npw turning to Google to find out about installing solar.

“I’m seeing consumer interest levels 10 to 20% up on what they were in the same time of previous year. All this hasn’t yet flowed through to leads proposals and sales,” Johnston said of the spike in Google trends for “solar” and “solar panel.” He said that it's “the highest level it's been … and paybacks [on solar systems] are all improving now, so that bodes well for 2024 as well. My prediction is that we are going to have a strong finish to the year and have a record year for 2023.”

The average size of solar systems in Australia is also at record high, with especially strong growth in 10 kW to 15 kW systems. “The reason is because you’ve got commercial doing really, really well. Record year for commercial.”

Falling prices

Another interesting trend is that while Australian solar system prices are now falling after the pandemic hike, this has not translated to customers spending less overall.

This is demonstrated in the above two graphs, with the total dollar customer spend on top and dollars per watt below.

“If you look at the dollar total spend, it’s pretty consistent and flat. So this to me is saying as panels are getting cheaper, people are putting more of them on,” Johnston said.

From pv magazine USA

FERC's new energy infrastructure report shows that solar holds the largest share of capacity additions in the energy mix in the United States. 

In the January-August period, just under 9 GW of solar capacity was added, representing 40.5% of all capacity additions. This represents 36% growth year on year. 

Wind power provided an additional 2.7 GW, accounting for about 12.5% of new capacity additions. When including solar, wind, hydropower, geothermal, and biomass, renewable energy sources contributed 54.3% of capacity additions. 

Much growth lies ahead for decarbonized energy to push out fossil fuel sources. For total available installed generating capacity, natural gas remains the leader. More than 44% of available electricity generation capacity comes from natural gas, followed by coal, wind, hydropower, and solar.

FERC forecasts strong growth in solar for years to come. It expects more than 83 GW of “high probability” solar capacity additions through August 2026. This dwarfs the 4 GW of natural gas additions expected through that date. 

FERC said that the 83 GW of “high probability” solar additions may be quite conservative. There are more than 214 GW of solar additions in the three-year project pipeline. 

Natural gas has 564 GW available installed capacity today, while solar has 92 GW. Looking ahead three years, if solar were to add all the projects in the pipeline to the grid, it would reach 306 GW. The figures suggest that with a healthy ramp-up of projects, solar could feasibly push out natural gas as the No. 1 provider of electricity by 2030. 

Reaching status as the number one provider of electricity will take significant funding. A report from Rhodium Group and the Massachusetts Institute of Technology (MIT) showed that the United States’ total investment in clean energy, clean transportation, building electrification and carbon management reached $213 billion over the last year (from July 1, 2022 to June 30, 2023). 

The $213 billion invested represents a 37% leap over 2021-22 investments of $155 billion. Clean investment continues to strongly increase each year. In 2018/2019, total investments reached $81 billion, and it has climbed every year since.  

Domestic manufacturing of clean energy technologies has become an increased focus in recent years, and rich tax credits and incentives have served as an attracting force. Manufacturing investments totaled $39 billion in 2022/2023, more than doubling the $17 billion invested in the previous report period.  

Solar represented the largest energy and industry investment category in the second quarter of 2023, attracting $8.62 billion. This was followed by storage with $4.08 billion, and wind with $2.03 billion.

From pv magazine 10/23

Solar installations in India have been steadily rising since March 2023. As per official numbers, India installed 9 GW (AC) of solar capacity from January to August 2023, which is around 12 GW of DC capacity, according to estimates. These installation numbers reflect many projects that were originally supposed to be built in 2021 and 2022 but were hindered by high equipment prices.

A government-approved relaxation of restrictions imposed by the approved list of models and manufacturers (ALMM) – which indicates which products can be included in government-backed projects – has accelerated Indian PV installations, helped also by falling module prices.

The start of 2023 looked a bit gloomy for India, compared with the usual pattern of a strong first quarter each calendar year. Module price and availability prevented many projects from being completed. In May, after the SNEC solar trade show in China, the market turned around. Module prices, excluding import duties, quickly dropped below $0.18 per watt (W) and continued to fall, reaching less than $0.15/W in the July to September period. Installers took the chance to complete pending projects, driving the current installation boom, which is likely to continue through the first three months of next year.

Rising imports

Local developers have grabbed the opportunity offered by module price declines to order in bulk. We believe that will lead to a strong upswing in module imports in the final three months of this year and the first three months of 2024. These modules will go into projects in the first part of next year and possibly even further out, depending on how legislation evolves.

Current regulation allows for government-tendered projects to include modules not named on the ALMM list, until March 31, 2024. Modules imported before that deadline but not installed will not be eligible for installation on government-aided projects. Developers are trying to persuade the government to extend that deadline by another three months, to give them more flexibility in terms of orders and imports.

Expanding production

Module manufacturers have ramped up India’s solar panel output, with annual production capacity expansions driven by national local-content policies. Annual module manufacturing capacity in India has already crossed the 20 GW mark but the factory utilization rate remains below 50% to date. That means, with local manufacturers having brought their prices closer to the cost of imported modules (plus basic customs duty), they will not be able to meet demand.

The fall in imported solar cell prices has resulted in a strong spike of cell imports over the past few months, which is likely to boost solar module-assembly factory utilization rates. The share of Indian-manufactured modules in new installations is expected to increase accordingly, especially after March 2024.

The combined generation capacity of imported and locally manufactured modules is still not enough to supply the 60 GW (AC) or so of solar projects that the Central Electricity Authority reports as being at some stage of construction.

Projects corresponding to more than two thirds of this capacity are unlikely to obtain modules before March 31, 2024. Hence, most developers of government-backed projects will need to procure modules included on the ALMM list. Such constraints on module procurement put the solar project pipeline at risk of delays.

In parallel with the government-backed PV project pipeline that dominates the Indian solar market, there is also growing interest among commercial and industrial electricity consumers seeking to procure solar power via on-site systems or private power purchase agreements. As these are not limited by ALMM list requirements, these segments of the solar industry are in position to benefit from possible module inventories in 2024. India’s PV deployment is, hence, set to diversify further across different market segments.

Given the high number of PV projects waiting to be commissioned and the level of module imports expected for the rest of the year, S&P Global Commodity Insights forecasts India will have installed 20 GW of solar this year. Solar installations in 2024 could be even higher than our forecast, depending upon government policy and possible further ALMM relaxations. Deadline extensions are possible, as we have seen previously in India’s solar power market.

About the author: Josefin Berg is an associate director for solar research at S&P Global Commodity Insights, leading a team that covers forecasts, trends, and company strategy in the downstream solar market. Her focus areas include developers and engineering, procurement and construction business strategies, demand for PV in emerging markets, and the role of solar in the power mix. With more than 12 years of industry experience, she writes reports on PV markets and trends and regularly speaks at industry events.

Researchers from Spain have simulated the effect building integrated photovoltaics (BIPV) will have on the energy consumption and the economics of high-rise office buildings in the Mediterranean area.

They presented three different BIPV integration scenarios for the GESA building, an office building built in the 1960s in Palma de Mallorca, in Spain's southern archipelago of the Balearic Islands.

“Despite of its iconic and protected status, the GESA building has been abandoned for several years, hence it requires a refurbishment that will also update its skin to the current energy efficiency standards,” the scientists explained. “The inefficient envelope, location (isolated and in a sunny climate), and representability of a typology of office building make it a good reference for studying the impact of refurbishing with BIPV.”

Via the TRNSYS simulation software, which is commonly used to simulate the behavior of transient renewable systems, the group simulated the impact of BIPV taking as reference a representative floor. As in the physical building, among the parameters inserted are the GESA building’s curtain wall structure, which is 77% composed of semi-transparent windows and 23% of non-window opaque areas. As the building, although abandoned, is protected by a local heritage commission, the façade design has to keep its original characteristics.

The reference scenario was based on the existing double-glazing Parsol Bronze window. It was compared to four other scenarios, one with only solar control windows; the second with solar control windows and BIPV modules in the opaque area; the third with only transparent BIPV windows; and the fourth with BIPV windows and opaque BIPV in non-transparent areas.

“The data for the transparent PV used in this study is based on a prototype currently in development, hence there is room to improve the thermal, optical, and electrical properties to better fit the building needs, as well as to increase the PV conversion efficiency,” the research group emphasized.

According to the results, the final energy consumption in the existing reference case was simulated at 51.3 kWh/m2. In the case of only solar control windows, this value reached 45.8 kWh/m2, with very similar results with the addition of opaque BIPV. However, in this case, the building will be able to use 5.8 kWh/m2 and export 2.6 kWh/m2 to the grid.

In the case of only transparent BIPV windows, the energy consumption will be higher, as that module will block more of the solar radiation and, therefore, result in higher heating and lighting demands. Overall, that system will require 49.8 kWh/m2 while consuming 5.1 kWh/m2 and exporting 2.2 kWh/m2. In the case of using window BIPV and opaque BIPV, the demand will reach 47.6 kWh/m2, while self-consumption will take 10.9 kWh/m2 and 5 kWh/m2 will be exported to the grid.

“The results show the potential of the BIPV solutions for improving the energy balance of the building. The transparent PV reduced the energy demand by 6.9% and the total energy balance by 21%,” the scientists added. “The opaque PV further improved the results of the two glazing system solutions, the energy balance improving to 28.1% and 38.3% with the solar control and transparent PV solutions, respectively.”

The researchers also conducted an economical analysis, which they claim showcases the “relevance of the electricity pricing schemes into the promotion of BIPV.” The components and installation cost of the components were mostly obtained from a construction materials database, while the cost of the prototype window BIPV was assumed at €200 ($210.65)/m2.

They looked into two tariff levels. The first is based on current Spanish tariffs and demand, while the second assumes a high penetration of PV into the national grid. In this case, the net load of high-penetration photovoltaics presents a very low price. Another variable was the compensation for the electricity sold to the grid by the building, which they estimated at either 0%, 30%, or 100% of the electricity price.

Currently, 30% of the electricity price is the typical export value in Spain. Under this assumption, with the current price profile, the discounted payback time for solar control will be 24 years, for solar control and opaque BIPV it will be 14 years, for window BIPV only it will be over 50 years, and the combination of both BIPV technologies will result in a payback time of 24 years. In the assumption of high PV penetration and 30% electricity price, however, the payback time in all systems may exceed over 50 years.

“The lower average electricity price and, more importantly, the timing of the generation in the ‘high PV’ scenario explain the significantly worse payback periods,” they concluded.

Their findings are available in the paper “Impact of building integrated photovoltaics on high rise office building in the Mediterranean,” published in Energy Reports, which also included an economic evaluation. The research group comprised academics from The Technical University of Catalonia and the Catalonia Institute for Energy Research.

Researchers led by the German University of Technology in Oman have looked into the effect of dust accumulation on PV systems and claim to have identified an optimal cleaning cycle in economic terms.

The scientists have conducted the research on an experimental setup located in an area next to their campus. “The research might be valid to countries with dry weather, humidity during summer, and high temperature,” the research's corresponding author, Ali Al Humairi, told pv magazine. 

“Photovoltaic energy is considered the most viable renewable energy source in the Middle East and North Africa region due to the high solar irradiation level and the number of clear sky days during the year,” the group said. “However, environmental factors such as dust limit the optimum utilization of the source.”

The experimental setup included two identical strings of nine PV modules connected in series, with one string being dry-cleaned daily and the other not. The 5.85 kW ground-mounted system was south-oriented and had a tilt of 17 degrees. The modules were based on polycrystalline cells, and each had a peak power of 325 W. The system included an inverter with 98.5% efficiency.

The observation of electrical and weather parameters began in November 2020 and ended in April 2021. “The experiment was conducted in the winter and spring seasons, which generally have less soiling rate and air contamination,” the researchers explained.

Comparing the cleaned string to the non-cleaned string, the academics found that dust led to up to a 28% reduction in the PV current performance and up to a 24.2% reduction in the PV power. Overall, the average difference in the current performance was 14%, and in PV output it was calculated at 11%.

“The difference between the uncleaned and the cleaned modules’ output current has increased exponentially during this period,” they said regarding the current. “In November, the difference in current is about 2%, which increased with time; in December and January, it is about 5% and 10%, respectively. The momentum intensity slightly dropped in February and recorded a difference of 18%. This was followed by a less momentum increment in March and April, resulting in a difference of 22% and 28%, respectively.”

As for the PV power output, they found no substantial effect in the first three months, with the difference being 0.1% in November, 1.9% in December, and 7.7% in January. However, it was much more noticeable in the next three months – with a 14.7% difference in February, 19.3% in March, and 24.2% in April.

For its economic analysis, the team used a fixed rate tariff of $0.11 per kWh. The cleaning rate was set at $1.30 per hour per worker, and according to the paper, one person could clean the whole system in one hour. Using this data, they have found the recommended cleaning interval to be once every one or 1.5 months, resulting in 8 to 12 cleaning cycles per year.

The group presented its findings in the paper “Experimental Investigation Of The Soiling Effect On The PV Systems Performance And The Cleaning Intervals In Oman,” published in Solar Energy Advances. It also included scientists from the Sultan Qaboos University, Muscat University, and Germany’s Duisburg Essen University.

“The effect of the accumulated dust was evident in the third month of the experimental period, indicating the necessity of conducting a cleaning cycle for fewer than three months to avoid losses,” the researchers concluded. “However, the results could vary depending on the location, season, geographical and meteorological conditions.”

A group of researchers from the National University of Sciences & Technology (NUST) in Pakistan has developed a PV system fault forecasting technique based on variations in solar cell current and voltage parameters.

“Existing fault detection techniques detect faults after their occurrence,” the research's lead author, Ihsan Ullah Khalil, told pv magazine. “Our proposed fault forecasting technique forecasts the fault so that predictive maintenance can be assured. It uses the rate of change of solar cell parameters to identify which fault is occurring.”

According to Khalil, solar cell parameters start changing even before a fault occurs. “The IV curve is divided into 172,000 data points, so we get 172,000 values of I and V,” he further explained. “Then, by using each value of I and V, and the values of Im and Vm, we extract the same number of values for each solar cell parameter. Finally, we model the rate of change of each variable for the first 100 data points. For the first hundred data points, I and V are almost the same up to the first decimal point.”

The proposed algorithm is claimed to be able to extract cell parameters at either no faulty conditions or faulty conditions and to sense fault at its inception level.

Machine learning-based regression techniques are used for the model, which the scientists said is able to detect variation trends of each parameter against each fault at the inceptive stage. The algorithm initially models the initial trend against a single voltage, current, and power value. It then splits the data set and models the variation of solar cell parameters using four variants of linear regression. “Linear regression has given excellent results,” Kahlil said. “One of the major contributions is introducing a lemma for the fault index formula that is not been discussed in the literature before.”

The scientists claim that the results demonstrate that the solar cell extraction method they used offer superior performance compared to existing forecasting techniques, as it analyzses the variation in cell current and voltage for the detection of faults at an incipient stage. “The significance of the proposed algorithm rests in its early fault detection capability, which contributes to the development of adaptive protection systems for photovoltaic installations,” stated the researchers.

Their findings were introduced in the study “A novel procedure for photovoltaic fault forecasting,” published in Electric Power Systems Research.

BIPV is one of the most promising pathways to net-zero energy buildings, representing an opportunity for hundreds of gigawatts of solar-generating building components to be installed worldwide. However, integrating BIPV into design is not easy, given the vast range of data and technical factors to be considered and the difficulties that designers and developers face in choosing and sourcing materials.

“BIPV design and management is a complex process which involves requirements geophysical, technical, economical and environment factors throughout the life cycle of the system, ranging from acquiring architectural visual effects to higher solar insolation in given location, efficient energy generation and economic operation and maintenance of the BIPV system,” Rebecca Yang, a researcher for RMIT’s Solar Energy Application Group, told pv magazine. “Lack of consideration for PV integration of the building envelope in the early design phase is one of the main reasons for complicating the design and construction process of BIPV systems.”

Yang has led the development of a new tool, BIPV Enabler, which is the first of its kind to combine BIPV product, regulation, technical, economic and construction data. The tool was developed with Australian data and features maps, a 3D shape library, solar visualizations, hourly weather data and pricing information for materials and feed-in tariffs.

“The Zero Carbon Australia Buildings Plan promotes BIPV to reach a full uptake on suitable buildings by 2030. BIPV is at Technology Readiness Level 9, but adoption has been slow in Australia because it reframes distributed solar energy as a building product which needs close collaborations between the PV and building industries,” Yang said. “It is difficult to develop a business case for a BIPV project without accessible information and value-for-money solutions.”

Yang said that BIPV Enabler is the perfect solution for building designers and developers looking to select the right solar option, be it for a new build or an existing building, by retrofitting BIPV.

“We’re making integrated-solar a more attractive option to developers, slicing the time it would normally take to research and implement incognito solar devices,” she said. “Our software aims to translate technical complexities into a packaged, user-friendly platform that integrates product, technical, economic and construction data to create the best BIPV solution for individual building projects.”

Yang, the director of the Australian PV Institute and head of the BIPV Alliance, said that the platform serves building professionals in making design choices and enables PV suppliers to showcase the value of their products to clients.

In BIPV Enabler, users have several key functionalities. They include the ability to select building types and project locations with an interactive map. Users can also create building models using the 3D geometric building shapes library or default arch and draft workbenches within FreeCAD. In addition, the platform allows users to visualize the solar irradiance on the building envelope.

The software, funded by RMIT and the Australian Renewable Energy Agency, was initailly announced last year and opened to users mid this year. “We provide a one-year usage for free at this stage,” Yang said.

She claimed that with minimum effort and some funding support, the RMIT team could redesign BIPV Enabler to cover other countries. It is now on the lookout for such collaborative opportunities.

Researchers at the University of Science and Technology of China have developed a new system design for spectral-splitting concentrator agrivoltaics (SCAPV)

The system is based on the spectral separation of sunlight based on the difference in the spectral response of photovoltaics and photosynthesis. According to this principle, red and blue wavelengths are used for photosynthesis as they match the absorption peaks of plant chlorophyll, while all other wavelengths are used for concentrated power generation.

In the study “Large-scale and Cost-efficient Agrivoltaics System by Spectral Separation,” published in iScience, the scientists explained that the proposed system utilizes a dual-axis tracking technology with concentrator modules that optimize the cell components and the concentrating curve.

The 10 kW system occupies a surface of 400 m2 and consists of 128 concentrator modules, each integrating an ultra-white and toughened concentrating curved glass (CCG), a multilayer polymer film (MPF), which the researchers said is the key component for achieving spectral separation. Furthermore, 23%-efficient interdigitated-back contact (IBC) crystalline silicon solar cells with a concentration ratio of 6% were provided by Sunpower.

“These cells were cut into 1/3 strip PV cells (41 mm × 125 mm) and then connected in series using ethylene vinyl acetate (EVA) along with PV glass and a backboard, resulting in the formation of PV modules consisting of 24 such strip PV cells,” the scientists said, noting that solar cells with a higher concentration ratio would have resulted in higher system costs. Their selection process also took into account the spectral shift characteristics of the MPF, processing cost, module size, and holder height.

The concentrator photovoltaic panel consists of a back side receiving concentrated sunlight from the concave screen and a front side receiving direct sunlight. The tracking system uses two motors to control the angle of the spotting module for both azimuth and altitude angle tracking.

“The concentrator modules on the entire main beam square tube are driven via a drive shaft,” the researchers explained. “Integral brackets on the lower part of the concentrator module support the weight of the concentrator modules and wind/snow loads, and the weight is transferred to the primary beam through the north-south swing arm rotation shaft and the swing arm weldment.”

The SCAPV system was placed horizontally at a height of 2.5 m to allow small farm machinery to pass below it.

The system was tested in outdoor conditions in Anhui, China, and was found able to produce 107 MWh of electricity per hectare. Its overall system efficiency reached 11.6%, which the scientists said is the highest efficiency ever recorded for the spectral separation technology.

“Field planting experiments showed that five crops (ginger, peanut, sweet potato, bok choy and lettuce) had an average yield increase of 18.4% under SCAPV compared to open-air systems,” stated the research group. “The microclimate at the bottom of the SCAPV system, especially the soil moisture retention capacity in the daytime, was better than in the open air.”

The scientists believe that the costs of the system may decrease by 18.8% if around 1 GW of SCAPV capacity is deployed globally. They noted that the cost of the MPF currently accounts for around 50% of the system costs.

“Nevertheless, the laboratory's four-pronged plan – mass production of an autonomous film processing process, optimization of mechanical structures, development of lightweight modules, and the realization of scale effect – points towards heightened economic viability,” they concluded.

Solar photovoltaic, solar thermoelectric and wind energy production

In the week of October 9, solar energy production decreased compared to the previous week in the main European electricity markets. The largest drop, 23%, was registered in the Portuguese market. In the other markets, the drop in solar energy production ranged from 19% in Germany to 8.1% in Italy.

Despite the weekly drop in solar energy production related to the seasonal change, when comparing solar photovoltaic energy production in the first half of October 2023 with the same period in previous years, since 2019, the record was broken in all analyzed markets.

During the first half of October 2023, the highest photovoltaic energy production, 2036 GWh, was registered in the German market, an increase of 5.4% compared to the same period in 2022 and 62% compared to 2019. In Mainland Spain, photovoltaic energy production for the first 15 days of October 2023 was 1613 GWh, an increase of 37% and 286% compared to the same period in 2022 and 2019, respectively. The lowest production, 160 GWh, was registered in Portugal, but still represented an increase of 33% compared to 2022 and 228% compared to 2019. For the week of October 16, according to AleaSoft Energy Forecasting’s solar energy production forecasts, solar energy production is expected to decrease in the analyzed markets.

In the case of wind energy production, the week of October 9 brought a week‑on‑week increase in most of the markets analyzed at AleaSoft Energy Forecasting. The largest increase, 51%, was registered in the French market. In this market, 261 GWh was generated with wind energy on Friday, October 13, which is the highest value registered since the beginning of August. In the other markets, the increase ranged from 8.6% in Germany to 43% in Italy. The exceptions were the markets on the Iberian Peninsula, where overall wind energy production fell by 12% compared to the previous week.

For the week of October 16, AleaSoft Energy Forecasting’s wind energy production forecasts indicate that wind energy production will increase in all analyzed markets, except for Germany.

Electricity demand

During the week of October 9, electricity demand increased compared to the previous week in most of the main European markets. Increases ranged from 0.6% in the Belgian market to 6.2% in the German market. In the case of Germany, the rise was related to the recovery of the labor rate after the previous week’s celebration of Germany’s Unity Day on October 3. Something similar happened in Portugal, where Portugal's Republic Day was celebrated on October 5, which favored a 5.3% increase in demand in that market in the second week of October.

On the other hand, demand fell in only two of the main European electricity markets. In Spain, the drop was 7.6%, and it was related to the celebration of Spain's National Day on Thursday, October 12. Demand also fell in the French market, in this case by 0.6%.

During the same period, average temperatures fell in most of the analyzed markets, ranging from 2.0 C in Great Britain to 0.1 C in Germany and Italy. The exception was France, where average temperatures increased by 0.4 C compared to the first week of October.

For the week of October 16, according to AleaSoft Energy Forecasting’s demand forecasts, electricity demand is expected to increase in most of the main European markets, with the exception of Germany.

European electricity markets

During the week of October 9, prices in all European electricity markets analyzed at AleaSoft Energy Forecasting rose compared to the previous week. The largest percentage price rise, 70%, was reached in the Nord Pool market of the Nordic countries, while the smallest increase, 1.7%, was registered in the EPEX SPOT market of the Netherlands. In the other markets, prices increased between 5.0% in the EPEX SPOT market of Germany and 20% in the IPEX market of Italy.

In the second week of October, weekly averages were below €95/MWh in most of the analyzed European electricity markets. The exceptions were the Spanish, Italian and Portuguese markets. The Italian market reached the highest average, €145.30/MWh. In the case of the MIBEL market of Portugal and Spain, the averages were €125.39/MWh and €125.41/MWh, respectively. In contrast, the lowest average price, €9.25/MWh, was reached in the Nordic market. In the rest of the analyzed markets, prices ranged from €77.92/MWh in the German market to €90.55/MWh in the N2EX market of the United Kingdom.

Despite the increases in weekly average prices, in the second week of October, negative hourly prices were registered in the German, Belgian, British, Dutch and Nordic markets, influenced by high wind energy production values. The lowest hourly price, ‑€7.10/MWh, was reached in the Dutch market on Sunday, October 15, from 14:00 to 15:00.

But in the second week of October hourly prices above €200/MWh were also registered on several occasions in most of the analyzed European markets. This was also the case on Monday, October 16 in all analyzed markets, except for the Portuguese and Nordic markets. On that day, the highest hourly prices were registered from 19:00 to 20:00 CET. In the German, Belgian, French, Italian and Dutch markets, a price of €240.00/MWh was reached. In the case of the French and Italian markets, this price was the highest since August 24. On the other hand, in the case of the Spanish market, an hourly price of €220.00/MWh was reached on October 16 from 19:00 to 20:00 CET, which was the highest price since the end of January. On the same day and hour, the British market also reached the highest hourly price since January, at £241.19/MWh.

During the week of October 9, the rise in the average price of gas and CO₂ emission rights, the increase in demand in most markets and the general decline in solar energy production led to higher prices in the European electricity markets. In the case of the MIBEL market, wind energy production in the Iberian Peninsula and nuclear energy production in Spain decreased, contributing to the increase in prices.

AleaSoft Energy Forecasting’s price forecasts indicate that in the third week of October prices in most of the main European electricity markets might continue to rise, influenced by declining solar energy production and increasing demand in most markets. In the case of the German market, the decline in wind energy production might also exert an upward influence on prices.

Brent, fuels and CO₂

Settlement prices of Brent oil futures for the Front‑Month in the ICE market remained above $85/bbl during the second week of October. The weekly minimum settlement price, $85.82/bbl, was registered on October 11. On the other hand, the weekly maximum settlement price, $90.89/bbl, was reached on Friday, October 13. This price was 7.5% higher than the previous Friday.

In the second week of October, concerns about the impact of the Middle East conflict on oil supply and OPEC’s global crude oil demand growth forecasts exerted their upward influence on Brent oil futures prices. However, data showed an increase in crude oil stocks of the United States that exerted some downward pressure. On the other hand, in the second half of the week, the United States started to impose sanctions on tanker owners carrying Russian oil at a price higher than the maximum price imposed by the G7, which might also have an impact on supply.

As for settlement prices of TTF gas futures in the ICE market for the Front‑Month, they increased during the second week of October. On Monday, October 9, the weekly minimum settlement price, €43.95/MWh, was reached. This price was already 12% higher than the previous Monday. The weekly maximum settlement price, 53.98 €/MWh, was reached on Friday, October 13. This price was 41% higher than the previous Friday and the highest since mid‑February.

In the second week of October, prices were influenced upward by supply concerns due to instability in the Middle East, labor disputes at Australian liquefied natural gas export facilities and a pipeline leak in the Baltic Sea. In addition, the forecast of cooler temperatures in Europe also contributed to price increases, as these would favor an increase in gas demand for heating.

Settlement prices of CO₂ emission rights futures in the EEX market for the reference contract of December 2023 remained above €80/t during the second week of October. The weekly minimum settlement price, €81.75/t, was registered on Monday, October 9, and it was 1.2% higher than the previous Monday. Subsequent price increases led to a weekly maximum settlement price of €85.95/t, reached on Friday, October 13. This price was 6.8% higher than the same day of the previous week and the highest since the end of August.

Source: Prepared by AleaSoft Energy Forecasting using data from ICE and EEX.

AleaSoft Energy Forecasting’s analysis on the prospects for energy markets in Europe and the financing and valuation of renewable energy projects

Taipower, a state-run utility in Taiwan, has created a new bidding platform to sell renewable energy to small and medium-sized businesses.

“A single bidder may choose between six different packages according to their own needs,” Taipower said in a statement.

From pv magazine Australia

Boundary Power, a union between West Australian regional utility Horizon Power and Victoria-based electric engineering company Ampcontrol, has officially launched a standalone power system (SAPS) that uses solar power and a renewable hydrogen hydride battery to store and generate electricity when required.

Adam Champion, business development manager for renewables at Ampcontrol, said while the Hydrogen Integrated Stand-Alone Power System (HiSAP), is not yet commercially available, it has been created to explore technical factors across design, integration and operation.

“We will be using these learnings as input into our future renewable energy products,” he said.

The first of the HiSAPS, developed in conjunction with Sydney-based hydrogen energy storage system specialist Lavo and Melbourne-headquartered inverter manufacturer Selectronic Australia, has been installed at Ampcontrol’s LED manufacturing facility at Ringwood in Victoria.

Boundary Power General Manager Simon Duggan said the system uses the company’s Solar Qube, an integrated, foldout, solar-battery-generator combination. However, the traditional diesel generator has been swapped out for a self-contained hydrogen power system developed by Lavo.

“Through the collaboration with Lavo and Selectronic we’ve been able to come up with a uniquely designed solution that paves the way for what we can do in the future with standalone powers systems and renewable energy generation,” he said. “It allows us to demonstrate the capabilities of this Solar Qube unit being powered by a hydrogen electrolyser and storage system rather than using your traditional diesel generator. This is a really, really, really exciting time.”

The demonstration unit includes two systems. The standalone SAPS comprises a 4 kWp rack-mounted solar array, a 16 kWh battery energy storage system and a 7.5 kW inverter. This is coupled with a 20 kWh metal hydride hydrogen energy storage system (HESS) with an additional 6 kWp solar array (part of a rooftop array at the Ringwood facility) and 5 kWh of battery storage. The HESS also incorporates its own 2.3 kW electrolyser and 3 kW fuel cell to ensure all hydrogen used is renewably created on site.

“One of the unique things about the HiSAPS unit compared to standard stand-alone power systems is that it generates its own fuel internally,” Ampcontrol Research Engineer Thomas Steigler said. “It’s generating hydrogen and storing that within the unit.”

The entire system, including communications equipment for integration into metering and reporting systems, is contained within a weatherproof enclosure.

The newly unveiled demonstration unit will supply solar power to Ampcontrol’s Ringwood facility during daylight hours to meet daytime energy demand. Excess energy will be used to charge the battery energy storage system (BESS) and then the HESS. The BESS will be discharged to meet the power demand at night and during peak periods. The HESS will meet energy demand gaps where solar and BESS energy are not available.

The project was partly funded by the Department of Energy, Environment and Climate Action (DEECA) Victoria as part of the state government’s Renewable Hydrogen Commercialisation Pathways Fund.

Duggan said the project has offered an insight into the technology required to build hydrogen systems to store and provide electricity and the demonstration plant will provide crucial insight into the technical, regulatory and safety aspects of integrating hydrogen systems into a standalone power system.

“The funding allowed us to collaborate with experts in the field to design an innovative solution to demonstrate real-world application, paving the way for future commercialisation of HiSAPS,” he said.

From pv magazine 10/23

At the end of August, the Italian Council of State issued two different rulings. The institution is an important legal and administrative consultative body in Italy, with jurisdiction over the acts of all administrative authorities. With the two rulings, the Council of State effectively said that agrivoltaic projects cannot be treated as conventional ground-mounted PV plants.

“The two sentences outline a substantially different regulatory framework for agrivoltaics and traditional photovoltaics,” said Andrea Sticchi Damiani, a lawyer who was involved in the matter. “The administrative justice has filled the last gaps so the legislative framework for agrivoltaics is now completely clear.”

The two rulings relate to two projects in the Italian province of Brindisi, with generation capacities of 6 MW and 110 MW. The province is in the region of Apulia, which has one of the highest PV adoption levels in Italy.

“The criteria that were used previously, such as the consumption of territory with respect to normal agricultural use, is an objection that can no longer be raised,” Sticchi Damiani said. “They are not hectares taken away from agricultural areas. On the contrary, they are often formerly-unproductive areas that will become productive again.”

Italian ambition

REM Tec, an Italian agrivoltaic project developer with an international focus, describes itself as the first in the world to develop sustainable projects for solar energy production in the agricultural sector. The company’s French CEO, Ronald Knoche, says the primary hurdle for agrivoltaics in Italy is the lack of a clear definition of the technology.

France codified an agrivoltaic definition into law in March. While some details are missing, the definition specifies that land occupied by agrivoltaics should primarily be used for agricultural purposes.

Legal developments in Italy are slower even if commercial plans for agrivoltaics are more ambitious. In April 2021, the last Italian government, led by Mario Draghi until October last year, presented a €1.1 billion ($1.17 billion) plan to deploy a little over 1 GW of advanced agrivoltaic systems by June 2026. The installations must include “innovative” mounting solutions that place solar modules above the ground without compromising the continuity of agricultural operations.

“The Italian government has two approaches: a generic definition and a better way of doing it,” said REM Tec’s Knoche. “I don’t think it is the right way forward. Many stakeholders are accusing the local industry of doing ground-mounted agrivoltaic systems, ignoring the agriculture and landscape.”

He conceded that advanced agrivoltaic projects are expensive but suggested that the €1.1 billion fund is a way to support research activity seeking to establish best practice and avoid problems. Knoche mentioned Taiwan, which was a leader in agrivoltaic development before the Covid-19 pandemic. Concerning agrivoltaics, Knoche said, “It is now forbidden, as the industry was not doing projects very well.”

Follow the money

The REM Tec chief said the way to understand the power dynamic between agriculture and energy production is to follow the money.

Discussing the returns available from the two revenue streams, Knoche said, “A hectare will grant €100,000 for power production and as little as €2,000 for wheat agricultural production. This creates an imbalance, leading to some farmers receiving offers for land at €10,000 per hectare per year, from energy producers. It is an incentive to switch from agricultural production to power production: the income is higher and the risks are less. The Italian government seems to have partially understood it.”

Knoche said that agrivoltaics could account for the third-largest share of Italian PV power production in the future, behind traditional ground-mounted systems on industrial sites, and residential rooftop installations.

“Panel prices are decreasing, the knowledge about agrivoltaics is increasing, the economies of scale are such that the business models are changing, with agrivoltaics being one of the new business models,” he added.

The Joint Research Centre, the European Commission’s science and knowledge service, this year reported that agrivoltaic projects with 20 GW to 30 GW of generation capacity will have applied for administrative authorization under the national permitting process in Italy.

REM Tec worked with Italian standardization body UNI, national research agency ENEA, and the Università Cattolica del Sacro Cuore to draw up UNI/PdR 148:2023, a set of guidelines for the implementation of agrivoltaic projects.

The UNI standard, which incorporates existing regulations, has no practical application but proponents suggest it could facilitate permitting processes for local governments in Italy as well as administrative decisions for the country’s grid network authority, the GSE.

Land use

A Canadian inventor, Antoine Paulus, said new agrivoltaic designs are essential to decrease land usage. His own invention, dynamic building-integrated PV (DBIPV), is a mobile and removable system based on existing technology.

“My concept is based on shades with PV panels inserted in them, strung over the land with steel cables from mobile platforms at a higher elevation, to allow farm machines and livestock to pass under without obstruction,” explained Paulus. “With mobile platforms at the two ends, it is possible to stretch the shades over any area and close and move them or relocate them.”

DBIPV makes use of thin, light, and flexible PV panels, such as fiberglass-based silicon PV or organic modules. The steel cables are similar to those used in cranes. Paulus said his concept is safe as the units can be folded quickly in the event of an emergency.

“The fact that they are used in smaller clusters and each panel is in a sleeve separate from the other is another advantage,” Paulus added.

The Canadian inventor said that because the concept has not been tested yet, it is difficult to provide a levelized cost of energy estimate. Paulus said the utility of his invention is a no-brainer as it makes perfect commercial sense.

Alessandra Scognamiglio, coordinator of a task force on sustainable agrivoltaics at ENEA, said that similar, integrated projects have been considered before in the field of building-integrated photovoltaics but were not successful simply because of the effort required to create demand for them. “The market is generally not ready for innovation,” she said.

Apart from collaborating on the UNI standard, ENEA continues to research agrivoltaic projects. By the end of the year, it aims to release an online map that will assist with the selection of appropriate locations, based on factors that can positively affect co-located agricultural and energy production projects. Scognamiglio said the map would not include areas with restrictions on land use for PV.

The researcher, who also serves as president of sustainable agrivoltaic association AIAS, added that Italian authorities have so far placed little value on carrying out research activity on agrivoltaics, instead preferring to invest European Union funds in single projects.

“Private entrepreneurs are doing the research themselves, through universities and other entities,” said Scognamiglio. “The UNI standard is part of this context, a context where a clear regulatory framework is lacking.”

In June 2022, the Draghi government published guidelines for agrivoltaic projects but since the relevant minister did not sign them, they still do not actually have a legal basis.

“In October 2022, the government said it would make the necessary changes to the guidelines after discussions with operators,” explained Scognamiglio. “This has not happened.”

Legal position

Addressing Sticchi Damiani’s claim the legislative framework for agrivoltaics is now completely clear, Scognamiglio said that the lawyer is correct from a legal perspective.

“Any plaintiff who goes to court is now expected to win. This is not to say that a cultural gap has been filled because the word ‘agrivoltaic' is new, and it has not yet been defined,” she added.

That process is likely to lead to lawsuits or disjointed legal development. Scognamiglio warned that Italian regions have already started writing their own local guidelines on agrivoltaic installations in response to the number of requests they have received, and the scale of some of the projects. The Piedmont region, in northern Italy, published a principle for agrivoltaic projects in farming lands with high agronomic interest. The so-called “principle of continuity” requires agricultural production in the three years following the agrivoltaic installation to be at least 70% of the value of the farm output in the five productive years before deployment.

Shortly after Piedmont published its guidelines, the Italian government released a draft decree on “eligible areas,” a requirement of the soon-to-be-passed European renewables directive Red III. Scognamiglio confirmed that the constraints of the Italian draft decree would apply to some agrivoltaic projects: those on the ground, and inter-row PV systems. “It is most probably because agrivoltaics are still not credible enough to agricultural stakeholders, as the real difference between agri-PV and ground-mounted PV is not defined,” she said.

Industry pushback

Trade association Italia Solare says that the PV sector is being called on to achieve stringent renewables capacity targets. It believes that a preference for elevated systems would be detrimental to efforts to achieve these targets, as only 1 GW of annual installations, with high costs, could be achieved in the country with this technology. It notes that such arrays would also have a significant impact on the Italian landscape.

Rolando Roberto, vice president of Italia Solare, has argued constraints that include a preference for elevated systems could be viewed as counter-productive.

“Steel is no innovation,” he said. “Elevated systems with fixed maximal height sometimes do not make sense. Ministerial guidelines and other regulatory guidance documents qualify systems with minimum heights of 2.1 meters and 1.3 meters for agricultural crops and livestock activities, respectively.”

The PV association also said the sector must work on agricultural productivity data, analyzing different crops and climates. “Only when data are available can percentage constraints be introduced,” it explained. “Agrivoltaics must gain experience through experimentation, research, and development. In the meantime, however, it is necessary to allow the installation of efficient and truly achievable systems, in addition to experimental plants, even without the support of European subsidies.”

Perspective of farmers

At the other end of the debate, farming unions are asking for more restrictions on agrivoltaics. Coldiretti wants its members to be driving agrivoltaic deployment as, it argues, they will prioritize continuing food production on such sites.

“The integration of energy production in agricultural activities should not upset those balances that qualify agricultural income,” said Stefano Masini, environment and land manager at Coldiretti. “The sizing of installations should not depend on economies of scale or industrial logic, as is the case with ground-mounted photovoltaics.”

Masini argued that investments in agrivoltaic projects could be seen as a loophole to incentivize ground-mounted PV on agricultural soil. “According to data from the 2014 GSE statistical report, the area of panels installed on the ground at that date amounted to 13,877 hectares, of which 4,000 were in Puglia alone,” he said.

He said the total land requirements of ground-mounted solar projects meant that figure translated into around 30,000 to 35,000 hectares removed from agricultural use.

Scale

“The actual figure, however, is semi-unknown since, especially in recent years, there has been a sharp increase in incentive-free large-scale PV investment,” added Masini

The Coldiretti rep said that if utility scale projects were predominantly found on agricultural land, an additional 70,000 to 90,000 hectares could be taken away from agricultural use, equal to about 0.3% to 0.5% of current agricultural land.

Masini said he favors tailor-made installations that could increase farmer competitiveness but he cautions that there are significant complexities. Funds, which in some cases come from European Union programs, often have an expiration date.

“The need to make agrivoltaics a technology that can easily and quickly access energy incentives probably does not fit well with the complexity that requires an approach of real integration between energy and [agriculture],” he said.

Agrivoltaic expansion could also inflate land rental values, said Coldiretti, which claimed rental prices could rise by 40%. “The average bid for land for photovoltaic or agrivoltaic fields is four to five times higher than the normal market value. But, in some cases, it is as high as 10 to 15 times. It depends on the location of the land.”

Anomalous high pressure has delivered clear skies and high irradiance across both Mexico and eastern Canada whilst cloud associated with rain and storms depressed irradiance on the west coast of the US and Canada. Areas across Mexico and southern Texas saw reduced cloud, leading to 120-130% of average September Irradiance, according to data collected by Solcast, a DNV company, via the Solcast API.

Storms and a ‘Bomb” cyclone caused by persistent low pressure over British Columbia delivered cloudier conditions, leading to irradiance as low as 70% of long term averages.

Persistent high pressure reduces large cloud formation and redirects low-pressure cloud fronts, leading to periods of clear skies. In September large high pressure systems remained for longer than normal over both eastern Canada and southwestern US and Mexico.

For solar producers, these large and persistent systems have been especially beneficial with Quebec, Ontario and southern Mexico all seeing areas with 140% of the long term September GHI average.

Months like these bode well for the future of large solar installations in the south, with ERCOT having produced 3,301 GWh of Solar in the month. Mexico is also looking to take advantage of their high solar potential, through large solar projects like the planned 1 GW Puerto Peñasco solar plant.

Conversely, low pressure over western Canada & Alaska pulled in cloud from the Northern Pacific, leading to a significant increase in rainfall. This plus a ‘bomb’ cyclone in late September led to reduced irradiance across all of the Pacific Coast, most noticeable in British Columbia, where some locations saw just 70% of average September Irradiance.

Rainfall across the month was 7 mm/day above the September average, and temperatures were 5 C below average. Interestingly, this pattern of high pressure keeping skies clear and creating unseasonably sunny September conditions was also seen across parts of Europe, which also saw similarly high irradiance levels.

Mexico and the southwestern US can expect these conditions to reverse through winter, as El Nino winters tend to see Mexico and the South West under-perform against non-El Nino winter averages.

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

Up to 944 GW direct current installed capacity could be deployed if 1% (157,621 hectares) of utilized agricultural area (UAA) in the European Union applied agrivoltaic systems – a fivefold increase on the total EU installed capacity in 2022, a new assessment by the European Commission’s Joint Research Centre (JRC) states.

In the “Overview of the Potential and Challenges for Agri-Photovoltaics in the European Union” report, the researchers determined this figure assuming an installed capacity per land area of 0.6 MW per hectare, with the EU’s total UAA being 158 million hectares.

“Agri-PV potential of installed capacity is at TW scale for the two main land categories of arable land and permanent grassland and meadow assuming that they are covered by 10 % and 5 % with Agri-PV systems,” the paper states. “If the 10% of EU's UAA is covered with Agri-PV systems, the installed capacity could be between 3.2 and 14.2 TW, while only 5 % of coverage would lead to a total capacity comprised between 1.5 and 7 TW.”

Some parameters are still hindering agri-PV’s large-scale success, the JRC researchers found. Issues include no clear definition of what agrivoltaics is or what the European standards are, among others.

“One of the main challenges for Agri-PV is related to the absence of a clear and EU-harmonised definition, which could lead to land characterization changes when Agri-PV systems are installed on agricultural land. This change could have an impact on the eligibility to agricultural subsidies,” the document states.

Member states are also “general” in their plans to support investments in renewable energy, with support for agrivoltaics not explicitly mentioned in a majority country’s strategic plans.

“Technical challenges as well as challenges regarding the permitting and grid connection procedures have been also identified. In addition, there has been an increase in land prices impacting the welfare and security of the farmers. Finally, regardless of the technological advancements, there are still technical challenges that need to be addressed in order to maximize the electricity production while taking into consideration the biodiversity and without compromising significantly the crop yield.”

Agrivoltaics' potential could be unlocked if policymakers made changes, according to the report's 17 recommendations. This includes ensuring certified agri-PV systems were not excluded from common agricultural policy (CAP) subsidies; further research and development, and pilot schemes to overcome technical challenges; financial support through member states’ national policies was provided; and more.

Agri-PV deployment could also be fast-tracked through spatial planning and simplifying permitting and grid connection procedures, with the farmer's economic benefit and property security placed front-of-mind for governments.

“Even though it is not a new concept, the interest for this form of PV deployment has increased rapidly over the last few years mainly due to the increasing need for electricity production and the limited availability of new land due to the increasing global food demand,” the paper states. “Continued research and development, in particular cross-cutting studies that take into account energy, crop yield and biodiversity aspects, will be essential to overcome technical challenges and ensure fully sustainable solutions for the future.”

Researchers from China have assessed the accuracy of the WRF-Solar model in simulating global and diffuse radiation, pointing to its sensitivity to aerosol optical depth (AOD), cloud optical thickness (COT), and solar zenith angle (SZA).

The Weather Research and Forecasting (WRF) model was developed in 2016 within the Sun4Cast project funded by the US Department of Energy. The model is in the public domain and can be downloaded from the official WRF Github repository.

“Since the release of WRF-Solar, its performance in the simulation of diffuse radiation in localized regions in China and sensitivity to atmospheric parameters have not been fully explored,” the research group said. “This study aimed to test the simulation accuracy of WRF-Solar for global and diffuse radiation using satellite-based aerosol optical properties, which were obtained from a moderate resolution imaging spectroradiometer.”

The WRF model is widely used for weather forecasting. It uses the Rapid Radiative Transfer Model for Global Climate Models (RRTMG) scheme as shortwave radiation input, and the WRF-Dudhia as a radiation scheme. Additionally, the WRF-Solar model uses AOD input for its predictions, while WRF-Dudhia does not.

In their mission to emphasize the sensitivities of the WRF-Solar model, the academics have compared its predictions with real-life observations measured at Wuhan University. As for the AOD sensitivity, the researchers found that simulation error gradually decreased with the increase in the AOD. The parameter measures the scattering and absorption of light by tiny particles, or aerosols, in the atmosphere.

“The standard deviations of simulation errors corresponding to three different AOD ranges, of less than 0.4, between 0.4 and 0.8 and greater or equal to 0.8, were 162.12, 158.15 and 135.45 W m-2 of diffuse radiation, respectively,” they said. “However, when the AOD is greater or equal to 0.8, the model overestimated the diffuse radiation, with an average bias of 58.57 W m-2.”

As for COT, which measures how effectively a cloud layer scatters and absorbs sunlight, the researchers found the error to decrease with a COT increase. The standard deviations of the bias corresponding to COT range lower than 20, between 20 and 40, between 40 and 60, and more significant than 60, reaching 173.40, 149.45, 133.84, and 99.11 W m-2, respectively.

The scientists also looked at the dependence of WRF-Solar error on the SZA. “The simulation error increased as the SZA decreased,” they said. “When SZA <30 degrees, very discrete biases of simulated diffuse and global radiation were observed, with standard deviations of the bias of 245.40 and 286.65 W m-2 and mean differences of 79.20 and -3.62Wm-2, respectively. However, when SZA is between 50 and 70 degrees, the biases of simulated diffuse and global radiation were small, with standard deviations of 136.90 and 121.77 W m-2, respectively.”

However, comparing WRF-Solar to WRF-Dudhia, the researchers found the former to be superior. “In general, the improved WRF-Solar provides highly accurate forecasts in clear conditions. Under all-sky and cloudy conditions, poor comparison results of WRF-Solar and the traditional WRF model were obtained, and the simulated global solar radiation was largely overestimated.”

Their findings are available in the study “Assessment of the high-resolution estimations of global and diffuse solar radiation using WRF-Solar,” published in Advances in Climate Change Research. Concluding the article, the research group has emphasized the “need for improved representation of clouds and circulation in the model through physical parameterization and enhancements of satellite cloud and aerosol data assimilation techniques.”

The team included academics from China University of Geosciences and Hubei Luojia Laboratory.

From pv magazine Italy

Italian research agency ENEA and Enel Green Power, the renewable energy unit of Italian utility Enel, have developed a PV system that could be used in combination with the production of microalgae for food, cosmetic and pharmaceutical use.

“The algovoltaic plant, just completed at the ENEA Research Center in Portici, Naples, as part of an agreement between ENEA and Enel Green Power, allows an annual production of approximately 30 kg of dried algae on a surface area of 40 m2 and a power of 7 kW,” said the Italian research entity.

The system allows the cultivation of microalgae with a high commercial value, from €100/kg to €600/kg for pharmaceutical or cosmetic use, through a fully automated cultivation system integrated with the solar array.

“Algae allow us to exploit the energy coming from the sun better than traditional crops since they have greater photosynthetic efficiency,” said Carmine Cancro, a researcher at the ENEA Smart Grid and Energy Networks laboratory at the Portici Research Centre. “Furthermore, they have a high environmental value as they consume carbon dioxide, transforming it into biomass through photosynthesis and releasing pure oxygen into the atmosphere.”

Cancro said that the system could also be used to retrofit existing PV systems.

Italy finds itself 10 to 12 years behind other nations when it comes to renewables development and installation figures, thanks to a distrust of renewable energy generation versus more recognized forms of energy production, primarily nuclear, gas, and “clean coal.”

Finally, though, acceptance of the necessity of clean power is dawning. Italy will need to add 50 GW of solar generation capacity by 2030 as part of 70 GW of new clean power facilities needed to meet European targets.

A notoriously sluggish permitting system has resulted in less than 1.5 GW per year of new photovoltaics, with around 800 MW added in 2020 and 940 MW in 2021, rising to around 2.5 GW last year. Residential solar, at least, has advanced markedly in the last two years.

The government has also set a target of sourcing 55% of Italian-generated electricity from renewables by 2050.

Solar has been boosted by regional residential-PV incentives and a move to simplify permitting for clean energy plants under the procedura abilitativa semplificata (PAS), which came into force in April 2022.

Italy’s European Union-funded, post-Covid economic recovery plan, the Piano Nazionale di Ripresa e Resilienza (PNRR) – approved in July 2021 – allocated €1.5 billion ($1.6 billion) for the installation of solar on agricultural buildings, referred to as “agrisolar,” and €1.1 billion for agrivoltaics. None of the PNRR funds were allotted to conventional, ground-mounted solar parks.

That was mainly because of permit delays for conventional ground-mounted solar. While the PNRR millions fired the starting gun on agrivoltaic projects with a generation capacity of more than 1 MW, the drawn-out nature of the “autorizzazione unica” central permitting process for photovoltaics, and the diverse planning policies of local governments, have led to inevitable development hold-ups for ground-mounted solar.

Project clusters

The PAS has at least shaken things up, with many projects that were awaiting autorizzazione unica approval withdrawn and resubmitted as clusters of smaller sites, with generation capacities no larger than 20 MW in order to be eligible for the simpler permitting process. Numerous projects, in fact, have reappeared with a capacity ceiling of 14 MW, as securing connection to the medium-voltage grid is far easier than to the high-voltage network applicable to larger sites.

The raised cost of agrivoltaics reflects the fact panels cannot be as tightly packed as in conventional ground-mounted sites, due to the requirements of the crops planted under and between them.

Expensive

INTEC Energy Solutions' experience is that agrivoltaic installations with panels installed anywhere from 2.1 m to 6 m off the ground require 30% to 60% more expense than ground-mounts, when it comes to their racking and installation cost. That is because more steel is needed and work is performed at height.

Working at height and removing the extra dust generated by farm vehicles adds 20% to 40% to agrivoltaic array operation and maintenance costs, versus ground-mounted sites.

The lower panel density means agrivoltaics require 10% to 40% more expense to generate electricity and an additional €20 to €50 payment per hectare is needed to cover the cost of mandatory statements by the farmer proving the continuation of agricultural production at such facilities.

Those expenses ensure agrivoltaic sites are, on average, around 40% more expensive than ground-mounted facilities.

At INTEC, we are keenly following the progress of agrivoltaic-related legislation in Italy and also monitoring the details of projects our customers have submitted in pursuit of PNRR incentives.

There is great enthusiasm about the potential of agrivoltaics for Italy, and the Russia-Ukraine conflict has emphasized not only the European Union’s dependence on Russian gas – triggering a general energy crisis – but also a reliance on certain foodstuffs sourced from Ukraine.

The two problems must be tackled hand in hand and agrivoltaics represent an ideal method of ensuring agriculture and energy production coexist without imbalance.

Getting the policy right is essential to ensuring the nascent agrivoltaic and agrisolar sectors do not become another missed opportunity, with practically-inaccessible incentives for farmers.

Detail

At the time of writing, we are still awaiting detail of the operating rules for agrivoltaic systems to be eligible for public incentives and PNRR cash. Developers need to know what design, construction, and monitoring requirements will apply and how the PNRR eligibility of such sites will be verified.

Regarding agrisolar, on farm buildings, a tender for such arrays was issued on July 21. Online applications must be submitted to the organization set up for the purpose by government renewables body the Gestore dei Servizi Energetici (GSE), with an application window due to have opened on Sep. 12 and set to close today.

The tender included an increase in PNRR financial aid of up to 80% for companies involved in, or set to switch to primary agriculture; the option of multiple farms sharing consumption of the solar power they generate and of combining as single agrivolatic-project applicants; and a raising of the maximum eligible rooftop array generation capacity to 1 MWp.

The procurement document also doubled the previous maximum PNRR-eligible expenditure, up to €100,000 for accumulation systems, and to €30,000 for recharging devices, with a PNRR total per single project ceiling of €2.33 million.

About the author: Andrea Tedesco is country manager for Italy at INTEC Energy Solutions. He holds an MSc in electronics engineering and has solar industry experience as a senior project, technical, and area manager; sales and marketing director; and business unit manager. His expertise includes new-business and product development, project management, and building alliances and partnerships.

Mibet, a Chinese mounting system supplier, has introduced the MRac Waterproof solar carport solution, featuring a patented waterproof design to ensure excellent water resistance.

The “MRac Waterproof” design ensures waterproofing through its inherent structure, using surface-component structures for drainage. The upper rail support components are secured by side pressure blocks and middle pressure blocks, with aluminum alloy cover plates placed between component connections and EPDM single-ply roofing membrane strips installed.

“This tight component connection structure can block most rainwater,” a spokesperson from the company told pv magazine.

The carport also relies on a dual-track design at the bottom of the components for bidirectional water leakage prevention.

“Horizontal gutters are used on the upper level to direct excess water into the main gutter, which then guides the surplus rainwater to the drainage gutter,” the spokesperson said. “This ingenious multi-structural approach effectively addresses leakage concerns and achieves comprehensive waterproofing.”

The carport structure allows for the installation of both framed and unframed solar panels, offering a tilt angle ranging from 5 degrees to 15 degrees, in either portrait or landscape configuration.

According to Mibet, the carport mountings can be constructed from materials such as aluminum alloy, magnesium-aluminum-zinc, and carbon steel, demonstrating the capability to withstand 1.2 KN/m2 snow loads and 45 meters per second wind loads under standard conditions.

“Mibet's carport mountings are pre-assembled before leaving the factory, eliminating the need for cutting and welding on-site,” the spokesperson said. “Installation is completed by tightening bolts, significantly reducing construction time and lowering installation costs for users.”

The product comes with a 10-year warranty and is certified by TÜV Rheinland and SGS.

From pv magazine USA

Grid-forming inverters “are going to be needed once we get to very high levels of inverter-based resources,” said Ben Kroposki, organizational director of the UNIFI Consortium and director of the National Renewable Energy Laboratory’s Power Systems Engineering Center, at an RE+ conference panel discussion in September.

Solar, wind and storage resources are all inverter-based.

For 120 years, Kroposki explained, the electric grid has been based on synchronous generators, which can create the 60 hertz frequency used on the US grid to “black start” the grid after a complete blackout. Synchronous generators also synchronize to the existing frequency and provide other key functionality.

Most inverter-based resources installed to date use grid-following inverters. In the event that a large amount of generation goes offline, causing the frequency to fall below 60 hertz, generators that use grid-following inverters “try to keep online and inject power and keep the frequency stable,” Kroposki said. He referred to the solid red line in the graph above showing the modeled performance of a grid in which 73% of the generation uses grid-following inverters, following a sudden loss of generation.

The problem under that scenario, Kroposki said, is that the frequency drops below 59.5 hertz, shown with the dashed red line, in which case “the way to save the system is to drop some load,” resulting in a partial blackout, “and keep the rest of the system online.”

Grid-forming inverters, in contrast, can respond much more quickly to a frequency disturbance to maintain the frequency within range, Kroposki said, as shown by the green line in the graph. This capability is known as fast frequency response.

These modeling results were obtained by the Western Electricity Coordinating Council’s modeling and validation subcommittee.

The Texas grid operator ERCOT already occasionally reaches 71% instantaneous inverter-based generation, Kroposki said, which is very close to the 73% modeled in the scenario he described.

Some island grids are already past 73% instantaneous inverter-based generation, Kroposki said, including the Hawaiian Islands of Kauai and Maui, and Ireland.

Joining Kroposki in the panel discussion, Becca Jones-Albertus, director of the US Department of Energy’s Solar Energy Technologies Office, said that an annual renewable generation percentage of 60% to 80% on a grid implies instantaneous generation of nearly 100% for the inverter-based resources.

Hawaii already requires grid-forming inverters for their large-scale energy storage projects, Kroposki said. He described a project on the big island of Hawaii in which the National Renewable Energy Laboratory (NREL) is evaluating the performance of two grid-forming inverters made by different manufacturers, each with a capacity of at least 10 MW, working together on the island power system.

NREL is also rotating grid-forming inverters from different manufacturers through a 1 MW testing facility to ensure that they can all work together.

That type of technology validation is one key function of the UNIFI Consortium, while another is providing industry standards for grid-forming inverters. Consortium members are working to ensure that grid-forming inverters can provide voltage stability and regulation, damp oscillations, black start the grid, and provide cybersecurity.

The consortium is focused on helping commercialize grid-forming inverters, which are already available for battery storage. Grid-forming inverters for PV-only and wind-only projects are “about to hit the commercial market probably this year or next year,” Kroposki said.

Kroposki said the consortium offers a seminar series and other educational materials through its website.

UNIFI is an approximate acronym for Universal Interoperability for Grid-Forming Inverters. The US Department of Energy funds the consortium, which was formed last year.

From pv magazine 09/23

Polish PV project permitting, decided on the basis of conditions of development (decyzja o warunkach zabudowy), has long been relatively simple for developers to attain. However, a proposed new system would require developers to pass a local spatial development plan, which could be a considerably longer process.

According to the new law, change-of-land-use permission for solar plants would be offered only on the basis of local spatial development plans, for all arrays located on the most fertile, class I to class III agricultural land, or on forest land. The regime would also apply to arrays larger than 150 kW on less fertile, class IV agricultural land, and for projects larger than 1 MW on any other type of land. The size stipulation would be flexible for sites intended for business power production.

The recent draft legislation would offer developers the chance to secure permission before local plans are finalized, before Jan. 1, 2026. While previous planning decisions would remain valid indefinitely, those issued after the new law came into force would only be valid for five years.

Grid measures

On July 31, the lower house of the Polish parliament and the Senate prepared an amendment to the Energy Act which would oblige large electricity retailers to offer dynamic pricing, in line with EU regulation. The statute is now awaiting presidential sign-off.

With solar projects held up by grid capacity shortages, the legislation would also relax the rules governing generators installing direct transmission to electricity consumers, without using the grid. The Energy Act already allows direct lines, the key proposed change is a waiving of the obligation to obtain a permit from the President of the Energy Regulatory Office to build such a line. That permit requirement effectively blocks such projects because it may be issued only if the energy customer has no option of receiving electricity from the public grid.

The legislation would liberalize the construction of such direct lines and set out specific requirements. First, electricity could be supplied only from a separate production unit, that is, from a unit that has a total output going to one consumer. It would, therefore, be impossible to connect 25% of a PV plant’s nominal power output to the grid and supply the remaining power directly to a dedicated consumer. Secondly, all of the electricity supplied would have to be consumed by a dedicated consumer, that is, a user that is not connected to the power grid or is connected in a way that prevents the feeding of electricity produced at the third-party production site, to the grid. The amended statute would, however, allow the feed of excess electricity not consumed by the dedicated consumer into the grid. Any such arrangement would have to be agreed with the grid operator.

The new law would impose charges on grid-connected energy consumers for using electricity supplied via a direct line from a generator, with the fee payable to the local grid operator. The fee would not apply to customers who are not connected to the public grid and who create a type of “power island” together with the generator.

With such off-grid direct lines expected to be rare, it is anticipated most energy consumers that establish a line to a dedicated generator would have to pay the, so-called “solidarity fee,” which the statute would require to be calculated on the basis of the quantity of power supplied via the direct line. The charge would be meant to cover the maintenance costs of grid system-quality standards and ensuring the reliability of ongoing power supply. In other words, the consumer’s share of the fixed costs of transmission and distribution of grid electricity. The solidarity fee would be calculated by local grid operators.

Cable pooling

Another approach to enable the connection of new clean energy plants to the grid without waiting for infrastructure upgrades is also worth mentioning. This is cable pooling: adding new renewables sites to the grid via existing connections.

The Senate has proposed such an option by adding a comprehensive legislative amendment to this effect, to the bill amending the Renewable Energy Sources Act and Certain Other Acts. Cable pooling is about sharing a connection between more than one generation site. Such pooling makes sense for plants with different production profiles, especially PV projects sharing connections with wind farms, as they often produce electricity at different times of the day and neither uses their full connection capacity most of the time. Cable pooling will rely on physical security measures to prevent overuse of any connection capacity assigned. The cable pooling amendment put forward by the Senate is yet to be approved by parliament.

Last but not least, the trade in PV projects in Poland shows no sign of slowing down. The market is getting more and more professional. Buyers and project developers are increasingly seeking business partners on industry portals and classified advertisement websites.

About the author: Piotr Mrowiec is an associate partner at Rödl & Partner. He is head of the office in Gdansk, Poland and leader of the renewables team. As a specialist in renewable energy regulation, he advises numerous clients and conducts legal due diligence for PV and wind projects. Mrowiec has also been involved in studies for dozens of solar and wind projects.