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.”

The turbulent weather seen in recent months across Europe and beyond – crippling heatwaves, thunderous storms, and catastrophic floods – has once again highlighted the need to tackle the climate crisis by reducing our carbon footprint, and to transition to net zero as quickly as is humanly possible.

The United Kingdom government’s U-turn on some of its net zero commitments has placed an even greater emphasis on the role local authorities can and must play in creating a cleaner, healthier environment.

Members of the Key Cities network have shown a high level of ambition and proactive action in terms of achieving net zero, with many developing strategies, forming strong partnerships between community and private enterprise, and delivering successful projects across various sectors.

Crucial to these efforts is the development of sustainable energy. One technology which has attracted the attention of our Key Cities members has been solar power. Along with wind, solar offers the promise of renewable, sustainable energy and the creation of the infrastructure needed to collect and channel it is almost certain to lead to the creation of thousands of new, well-paid jobs.

Like many people, members of the Key Cities network were interested to hear, earlier in the year, of government plans to back technology which would, in effect, collect energy from the sun out in space using satellite-mounted panels and beam it back down to Earth.

It will doubtless take years to develop but as scientists work on this and other schemes to develop much-needed sustainable energy security, closer to home, Key Cities members have been making their own contribution toward greening our energy and power networks.

Findings

As spelled out in our “Levelling Up, Emissions Down: Accelerating Net Zero across the Key Cities” report, the United Kingdom has made significant progress in lowering carbon dioxide emissions in the last 30 years, with a reduction of 73.4% between 1990 and 2021, largely as a result of the closure of coal fired power stations and increased investment in low-carbon energy sources such as solar, wind, and nuclear energy.

There is still much work to be done but many of our network members have already embraced the challenge of creating more sustainable energy solutions. As well as having a significant environmental impact in these areas, these examples highlight the potential of solar power, should it be adopted more widely across the country. The English city of Wolverhampton has worked with the its local National Health Service hospital trust to install a 6.9 MW solar farm on a former landfill site to direct renewable energy to the hospital, meeting 70% of its electricity needs. In the English town of Blackpool, a major solar farm located alongside the city’s airport will provide sustainable energy to a nearby business enterprise zone.

In the Welsh city of Newport, a partnership with the Sustainable Communities Wales initiative driven by environmental charity Severn Wye and the Wales Cooperative has ensured 2,000 solar panels will be installed at the Geraint Thomas National Velodrome. This is expected to reduce the city council’s carbon emissions by 348 tons per year and will generate 1,973,MWh of electricity annually.

Funding secured through United Kingdom government body the Public Sector Decarbonisation Scheme (PSDS) has enabled the English metropolitan borough of Salford to install 2,562 solar panels on 21 public buildings across the city, generating 778 MWh per year. Four sites have also had battery energy storage systems installed and the 3.79 hectare Little Hulton solar farm, also funded through the PSDS, will triple energy generation.

These are encouraging examples but challenges remain. According to national electricity network operator National Grid, the United Kingdom government’s target of 50 GW of offshore wind by 2030 will require six times the amount of transmission infrastructure that was delivered in the past 30 years.

Local projects also require changes to the grid. One city in the Key Cities network is aiming to deliver 300 MW of renewable energy to meet its net zero targets; to date it has delivered 50 MW, with another 100 MW in the pipeline. Without an upgrade to the grid, however, it is unable to deliver more than this until post-2028 at the earliest, which will result in the city being unable to meet its net zero targets.

Economic benefits

The path to net zero is not only being driven by a need to address the encroaching climate crisis. Net zero solutions increasingly offer returns to the economy, over and above the economic benefits of preventing global warming. For example, renewable energy generation increasingly competes in cost terms with fossil fuels while the prices of solar and onshore wind have fallen by 88% and 68%, respectively, since 2010.

Investing in net zero solutions will have a range of other economic and social benefits, including job creation, improved energy security, and improved public health due to a fall in air pollution. Clearly, the road to net zero is not only essential to prevent climate change, but also to support the economies of places around the United Kingdom.

While local authorities are making significant contributions to achieve net-zero, greater autonomy through devolved powers and funding would significantly expedite progress and help overcome challenges such as capacity building across councils and the clarification of roles in the national net-zero transition. This is where the power of the network comes in, enabling Key Cities to harness the talents of both the community and the private sector, leading the charge towards a sustainable energy network and a climate-conscious future.

About the author: Cllr John Merry is chair of the Key Cities network and deputy mayor of Labour-led Salford City Council.

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.

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.”

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.

Scientists from Spain’s research center Tecnalia have encapsulated solar panels with a composite material that they claim has enhanced chemical recyclability.

The novel encapsulant material is based on glass fiber-reinforced composite material with an epoxy matrix containing cleavable ether groups. “The aim was to provide the encapsulating material and PV modules with enhanced chemical recyclability while retaining photovoltaic performance and durability,” the research group explained. “Further work will consider improving the moisture barrier properties of the composite, and adjusting the recycling conditions to allow component recovery valid for new modules.”

The researchers fabricated twelve solar module samples using monocrystalline silicon cells and encapsulated them with the new material using a linear vacuum resin infusion process. “As reinforcement, a glass fiber fabric with a 300 g/m2 (0/90◦) areal weight was used. The reinforcement layout consisted of 3 layers placed at the front and back of the cell. As a composite matrix, an epoxy resin system with amine base hardener and cleavable chemical groups in its composition was used,” they noted.

The group tested the performance of the panels and compared it to reference modules encapsulated with a standard resin system based on a clear bisphenol-A epoxy and an amine-based crosslinker. In the set of tests, the recyclable encapsulants were tested against the reference encapsulant, as well as bare solar cells without any kind of encapsulation.

“The data of the monomodules with the composite encapsulant based on the recyclable epoxy resin showed an electrical loss in short-circuit current of 6.3% when comparing the electrical performance before and after encapsulation,” the researchers said. “This value was slightly lower than the one obtained for the monomodules with standard epoxy composite, which presented a decrease of 7.2%.”

The group observed a similar trend when analyzing the power at maximum point (Pmp) losses and the external quantum efficiency (EQE) spectra, a metric for the efficiency and spectral response of photovoltaic devices.

The researchers also conducted a damp-heat test for 500 hours of exposure on the panel encapsulated with the new material, and found it showed an electrical loss in short-circuit current of 3.4%, which compared to only 1.5% for the benchmark panel.

“After 1000 h exposure, the observed short-circuit current decrease was even more pronounced, being significantly higher for the cleavable epoxy matrix,” the academics noted. “A final loss of 4.9% was measured for recyclable resin, whereas the standard epoxy showed a lower value of 2.8%. Regarding Pmp values, the loss reached 4.7% and 3.4% for the recyclable and standard composite respectively.”

In addition, the researchers carried out stability and aging tests for UV exposure and thermal cycling. As for the latter, it presented a loss of around 1% in short-circuit current and Pmp, which is not considered significant, as it is below the measurement accuracy of the technique. As for the UV exposure, electrical losses were also close to 1%.

The novel material was described in the paper “Composite material with enhanced recyclability as encapsulant for photovoltaic modules,” published in Heliyon.

Looking ahead, the researchers noted future work needed in both analysis and improvement of surface homogeneity, as well as studying the aging performance of the modules made with the recovered fibers, and possibly using a different resin-fiber interface.  Additionally, the researchers see opportunity to improve the proposed technology. “Future work will also be focused on improving the damp-heat stability of the composite, in a trade-off with a successful recyclability,” they stated.

From pv magazine 09/23

Charging an EV from a home solar battery is an attractive proposition as it can optimize individual consumption and boost the environmental credentials of car ownership. Working out the economics of home solar, batteries, and EVs, however, is a complex business. There are multiple factors to consider, most of which hinge on geography and electricity markets.

“EVs are typically unavailable to absorb excess electricity during peak hours of solar generation so you need a stationary battery to do that,” says Nelson Nsitem, an analyst on business data company BloombergNEF's (BNEF) energy storage team. “However, residential batteries are expensive so you would need quite a few things to make it work. This includes very high annual electricity consumption, a lot of excess solar generation to shift to the evening, low or no feed-in tariffs that pay for excess solar generation sent back to the grid, and time of use (ToU) retail electricity tariffs.”

Some markets appear to tick all the boxes. Researchers at the University of South Australia (UniSA) have calculated homeowners who charge EVs during the day, from solar and a battery energy storage system (BESS) can save up to 39.6% in annual energy costs, compared to petrol-car owners.

The researchers analyzed configurations featuring ToU tariffs and real loads, and PV-generation data from South Australian households, varying daily load demand, solar and BESS capacity and costs, and power export limits. “For motorists with private car spaces, home charging is the most convenient option but for those still totally reliant on the electricity grid for their energy, the costs could mount significantly,” said Professor Mahfuz Aziz when the research paper was published.

Energy savings

The UniSA researchers calculated that when solar panels were added, around 20% less energy was imported from the grid and, with batteries, the figure was around 83%. When EVs were added, the amount of energy consumed rose significantly but grid consumption could be reduced by around 89%.

“Our results demonstrate that households with petrol cars can reduce their annual energy costs by 6.71% using solar panels, and by 10.38% with the addition of a battery system,” said Aziz. “Replacing petrol-based cars with electric vehicles can reduce annual energy costs by 24% and 32%, respectively. The most significant reduction (39.6%) can be achieved with off-peak charging.”

In countries with cheap, EV-specific electricity tariffs, the equation changes.

“The cost of electricity at these times is significantly cheaper than normal-rate electricity and therefore reduces the benefit of using your own solar electricity,” says Ryan Fisher, BNEF’s lead EV charging analyst.

For instance, OVO Energy’s Anytime EV charging rate in the United Kingdom is GBP 0.10 ($0.13)/kWh. This compares to an average electricity rate of GBP 0.35/kWh to GBP 0.40/kWh, in addition to the energy provider’s promise to calculate the greenest time to charge from the grid, within limits set by customers.

“If we take an average of 3 MWh per year, and said all of that was avoided by using home solar, and that there were no losses, that would require a large portion of the yearly solar production for a 5 kW solar system, estimates say around 4.5 MWh a year,” says BNEF's Fisher. “It would therefore only avoid GBP 300 a year, or GBP 3,000 over ten years. A residential battery system is more like GBP 10,000 to install.”

Learning by doing

There are other reasons homeowners might want residential storage, however.

“Some people want to have backup power and others are just willing to pay extra to ensure they consume their own solar,” says Nsitem. Revenue stacking can also apply. The use of cheap solar for EV charging can supplement the use of battery-stored solar power during peak-grid-price periods. Throw in virtual power plant (VPP) participation payments – such as the $2/kWh paid to Tesla’s Californian VPP members – and bill savings can add up.

In 2021, a survey was undertaken of 8,000 households in Baden-Württemberg, in southwestern Germany, by the university Rheinisch-Westfälische Technische Hochschule (RWTH) Aachen. The results showed 30% to 35% of homes had solar, a stationary battery, and an EV. Since then, high electricity prices, rising EV adoption, and the trend for installing batteries alongside solar have likely raised the number.

Product announcements reflect the trend. In July, Tesla added a “charge on solar” feature to its Powerwall app enabling owners to automatically charge EVs from their solar battery.

However, the majority of EV charging management systems cannot communicate directly with stationary batteries. On the other hand, solar inverter manufacturers such as SolarEdge, Fronius, Growatt, SMA, and Sungrow – as well as battery suppliers including Sonnen, Senec, and Solarwatt – offer platforms that recognize home batteries when they are paired with PV and their proprietary electric-vehicle chargers.

As households continue to electrify, integrating all energy endpoints is likely to become an industry standard. Given the importance of interoperability, it is advantageous to have devices provided by one manufacturer. Separate apps and disjointed hardware can make things complicated for homeowners.

“Over time, companies will likely discover ways to integrate more of the power electronics for the solar, residential storage, and EV charger, which may help with the business case,” says BNEF’s Fisher.

Efficiency conundrum

Considering the storage capacity of most home and EV batteries, it appears odd to use stationary devices with, on average, five times less capacity, to charge the ones in cars.

“The home battery doesn’t know whether it is giving to another battery or to your washing machine,” says Gautham Ram, assistant professor of electric mobility at Delft University of Technology (TU Delft). “As long as it does the same amount of power and energy and the same number of cycles and depth of discharge, the aging is going to be similar. At the same time, you have to accept that you buy a battery because you want to cycle it frequently, so battery degradation is part of the picture. However, since EVs and heat pumps are flexible loads, it would make more sense to use the home battery for less flexible loads and reduce this battery’s aging via intelligent power control.”

Some residential batteries on offer today promise around 10,000 charging cycles during a 10-year warranty period. The average EV travel distance of 40 km per day corresponds to 7 kWh of charging energy – less than what a large home battery could store on a sunny day.

“Let us assume the EV charging adds 50% of a full cycle per day to a 14 kWh system during summer. Over a year, this adds up to about 100 full cycles, added to the same cycle number for the house, this amounts to 200 full cycles,” explains Jan Figgener, head of grid integration and storage system analysis at RWTH Aachen. “Even if 300 instead of 200 cycles per year are reached, the 3,000 full cycles within 10 years is still well below most warranty conditions. You won’t need all the cycles that the warranty states, in most cases, because the calendar aging will determine the product lifetime. Batteries age even when not in operation, just as we age while we sleep.”

The limitation does not lie with the PV system, either. While it’s clear that an array should be as big as possible to maximize the benefits of self-consumption, a typical 10 kW system could be sufficient to charge both EV and home storage.

Differing loads

“A big house might need around 5 kWh overnight and the EV could need 7 kWh for the average daily commute, which adds up to 12 kWh,” says Figgener. “You just need a couple of hours to produce this on a sunny day. The efficiency of EV charging is dependent on the power electronics, which show high efficiency at high power and low efficiency at low power. Here, a conflict between the power demand of the EV and the house arises.”

EV charging requires higher power – in the kilowatt range. House consumption, though, is typically around a couple of hundred Watts overnight. If an EV is charged solely from the stationary battery, the large inverter needed would, consequently, lead to high losses while covering household energy consumption.

“The best outcome would be to charge the EV directly from the PV system and this should only be necessary once or twice a week,” says Figgener. “The larger PV power matches the EV demand well and round-trip efficiency losses of the home storage system are avoided.”

In such a case, the residential battery could be smaller and would only be used as backup to charge the EV. Its main purpose would still be to cover household loads.

There are other ways of making solar-battery-EV synergy more frictionless. According to TU Delft’s Ram, an optimal way to improve efficiency is to integrate everything on the DC side with only one inverter. In such a setup, when power goes from solar to the home battery, it doesn’t have to be converted to AC and then back to DC to charge the EV battery.

“The DC-coupling can improve the power conversion efficiency by anywhere between 5% and 10% depending on if you’re having low or high power,” says Ram.

With only one inverter needed in this configuration, instead of three, the capital cost investment of the whole system would be much lower.

“With the DC integration that we are working on at TU Delft, and newer power electronics technologies based on silicon carbide, we can push the round-trip efficiency to new highs, especially at lower power, as well as save on the capex [capital expenditure] side,” Ram says. “However, we also need to think about bidirectional charging, which can offset an investment in the extra battery pack and deliver the same, or more value to the home.”

On July 1, the Dutch legislation on solar panel recycling changed and imposed importers selling solar panels to Netherlands' clients to pay a recycling fee of €40 ($42.50) per ton – a massive jump from the previous €6.50 per ton fee.

PV module importers are expected to pay this fee until 2025 to the OPEN Foundation, a Dutch nongovernmental organization.

Jan-Willem Jehee, operations manager at Stichting Zonne-energie Recycling Nederland (ZRN), today told pv magazine that the organization, which advocates for solar stakeholders and works with the OPEN Foundation, wanted to “offer some transparency” around the schedule change.

“We had a change where usually it's €6.50 ($6.98) per ton put on the market for solar module [and] that increased to €40 – so that's a sixfold increase as of July 1 this year. Where does this €40 come from? What are we doing with the money? That kind of stuff we want to clarify,” he said.

The organization hosted a public consultation last week answering questions about the fee change, which fits in with the European Union’s Netherlands’ 2014-mandated Waste Electrical and Electronic Equipment (WEEE) Directive. The directive aims to minimize the block's electrical and electronic waste.

Another policy change ZRN wanted to provide information about was the new warranty fund or security deposit, also mandated as part of the Netherlands’ 2014 WEEE Directive, Jeehee said. “You need to offer security, that as a producer you are able to pay for recycling in the future,” he explained.

“The WEEE says the way you're importing, or if you're bringing a solar module into a market in Europe, you're responsible to collect it when it becomes waste, and to make sure it's recycled when it comes to waste,” he added. “What we're doing in the Netherlands is we are introducing this guarantee fund, which is basically a fund with money aimed to absorb shocks in the market should one occur.”

Asked if he expects shocks to the market, Jehee answered: “In the coming 20 years, for sure.” He added there may be many “uncertainties” which will buck assumptions, surrounding demand and therefore price, but it is expected one day there will be, “less market growth than what is anticipated.”

“If you're talking about an increase of your waste streams, we will have large guarantees of solar modules for 25 years, sometimes 30 years, but that's the technical lifetime,” Jehee said. “You don't know the economical lifetime. You don't know, for instance, when a household will be ready to replace old modules installed in 2010 with a new version. We have a belief of what it will be, but it might turn out to be different.”

What Jehee is confident of is that if there is exponential growth of solar uptake – as there is estimated to be – then treatment and recycling fees are expected to grow exponentially to match. This is where the security deposit comes in. “In order to be able to offer this stable pricing, we say we're going to set some money apart in a fund, and this is this guarantee fund,” he said.

ZRN collected feedback from solar stakeholders until the end of last week about their initial thoughts on the fund and plan on publishing results from the public consultation “soon,” Jehee said. There will be one more round allowing stakeholders to give further feedback before the body submits their recommendations to the OPEN Foundation, which will make the final ruling.

Jehee expects the guarantee fund to be ready between the end of this year and sometime next year.

He said at present there was not enough solar waste to warrant treatment facilities in the Netherlands, with low volumes transported and managed outside the country adhering to Dutch law. “How will it be done in the future when waste streams start growing? Of course, it will be different,” Jeehee said.

The International Renewable Energy Agency (IRENA) estimated there would be more than 78 million tonnes of cumulative PV waste material by 2050, the organization said in 2016.

Recycling or repurposing solar PV panels at the end of their roughly 30-year lifetime can generate an estimated stock of 78 million tonnes of raw materials and other valuable components globally by 2050, the report added. “If fully injected back into the economy, the value of the recovered material could exceed $15 billion by 2050.”

Mauritania could be in an advantageous position to export hydrogen to international markets, potentially surpassing countries such as Morocco and Egypt in this regard, according to Michaël Tanchum, a non-resident fellow at the Middle East Institute. Mauritania's smaller population, vast coverage by the Sahara Desert with abundant direct normal irradiation (DNI) levels, and rich wind energy resources contribute to its favorable position. Additionally, being the only Sahel nation with a coastline allows Mauritania to facilitate off-take for export markets.

Galp has made a final investment decision on two large-scale projects to reduce the carbon footprint of the Sines refinery, including a 100 MW of electrolyzers for up to 15 ktpa of green hydrogen production. The unit, for a total investment of €250 million, is expected to have its first start up in 2025. The electrolyzers will be supplied by renewable power, originating from long-term supply agreements. Plug Power was awarded the order for the 100 MW proton exchange membrane (PEM) electrolyzers, while Technip Energies will be the main EPCM provider.

In 2012, as a board member of the Association of Alternative Fuel and Energy Market Participants of Ukraine, I took part in a meeting of renewables companies with the leadership of energy regulator the National Commission for State Regulation of Energy and Utilities. The main topic was the development of home solar in Ukraine.

The regulator was not receptive. Our decentralization arguments were met with skepticism, to put it mildly, by representatives of the old Soviet centralized power generation system. One of the commission members said the idea home solar could be a useful market segment was delusional, therefore there was no point developing it.

Exactly 10 years later, home solar arrays became almost the only source of energy for Ukrainians left without electricity due to the centralized energy infrastructure destroyed by Russian missiles and bombs.

As the world becomes increasingly reliant on technology and digital systems, the need for secure and reliable energy becomes ever more pressing. While traditional, fossil fuel-based systems have long been the mainstay of global energy, growing awareness of their negative environmental impact, the finite nature of such resources, and the rising potential for geopolitical conflict has prompted a renewed focus on decentralized, renewable energy systems.

Obvious targets

Ukraine has become a vivid example of how the centralization and monopolization of an energy system can lead to tragic political, environmental, and economic consequences. The nation's chronic dependence on Russian energy sources, in particular, oil, gas, and nuclear fuel, created the prerequisites for almost 100% Russian control over the Ukrainian economy. A similar situation has developed in many European countries.

After more than a decade of advocating for the decentralization of Ukraine's energy system, I was pleased to see president Volodymyr Zelensky declare the such an aim will be a state priority. It is essential that governments and private sector actors prioritize the development and deployment of decentralized renewable energy systems in order to ensure a secure and sustainable energy future. Action must not be blocked by fossil fuel energy lobbyists or short-sighted thinking. In Ukraine, for example, the development of decentralized renewable energy systems has been held up for over a decade by various energy lobbies, including the Russian nuclear industry. As a result, only 70,000 households have been able to benefit from the security and resilience of decentralized systems, rather than the millions that could have done so.

Warnings

Energy dependence has created very dangerous conditions for military aggression. In 2014, my consultancy and cleantech thinktank the Innovative Business Centre (IB Centre), together with former German Green Party MP Hans-Josef Fell, organized the EuroSEF 2014 event in Brussels. The energy security forum saw industry experts and members of the European Parliament discuss the new energy configuration of Europe in the context of dependence on Russia. Unfortunately, not everyone understood the scale of the threat then.

The leadership of Russia, the largest supplier of energy carriers to the countries of the European Union, expected that during its invasion of Ukraine, Europe would pretend the war did not concern them and would instead choose economic stability based on Russian gas, oil, and nuclear fuel. We cannot say all European countries passed this test.

What is the solution in such a situation? Diversification of energy supply and decentralization. Furthermore, decentralization also holds paramount strategic significance.

A centralized system is an easy target for cruise missiles. In the case of Ukraine last year, the Russian military purposely destroyed the country's energy system by bombing transformers, leading to widespread blackouts. Ukrainian households and companies that had installed autonomous renewable energy systems, such as solar panels and biofuel heating and electricity systems, were able to continue to have access to electricity and heating, demonstrating the inherent resilience and security of decentralized systems.

In 2011, the IB Centre started a pilot project within the framework of the Ukrainian Association of Renewable Energy. We decided to lobby for the opening up of the solar energy market to households.

The renewable energy association was the first such body in the Ukrainian cleantech industry, which at that time united more than 75% of players in the clean energy market. We communicated the aims of our project through the resources of the IB Centre, which at that time managed the leading new energy industry information platform, had its own news agency, and produced industry publications from the cleantech sector.

We immediately found ourselves at the epicenter of lively discussion, which mainly centered on the fact that representatives of legacy energy systems were inventing reasons why individuals could not become solar energy generators. Those disputes continued until 2015, when the Ukrainian parliament finally adopted amendments to a law enabling a green tariff for individuals – homeowners.

Trigger for change

The war in Ukraine became the trigger for radical change in the European energy paradigm. Today, most of the countries of Central Europe and Eastern Europe quickly adopt legislative changes aimed at the development of decentralization of energy, in particular solar energy, without too much delay and prevarication.

A great example of a rapid pivot to green, decentralized energy is Romania. In July, the country’s Ministry of Energy announced a finance program for solar arrays on social infrastructure facilities that is worth more than €500 million ($535 million). At the beginning of this month, the Ministry of Agrarian Policy of Romania announced the launch of a finance package for solar panels for farmers worth almost €1 billion. A little earlier, Romania had already announced an intent to install 160,000 solar roofs in the next two years.

That is why we have chosen Bucharest as the venue for CISOLAR 2023, the 11th Solar Energy Conference and Trade Show of Central and Eastern Europe, which will take place in the Romanian capital on Oct. 30-31. We want to write a new page of energy transformation in the region and demonstrate that even the most centralized systems in Europe can be transformed into green, decentralized ones with the help of solar energy. After all, there are simply no other options for the evolution of our energy systems.

About the author: Julia Daviy-Berezovska is co-founder of US-based organizations the IB Centre and the Sustainable Innovations Council. She has received worldwide recognition as a pioneer in technology for sustainability and a leading advocate for the progression of clean technology in developing economies. Julia was instrumental in liberalizing Ukraine's solar energy sector for independent organizations and private households.

From pv magazine 09/23

The most extreme situation in European electricity markets this year occurred during the first weekend of July. Europe saw, for most of the day, negative wholesale prices across the whole continent, from Finland to Spain.

Paradoxically, consumers in countries such as Ireland and Denmark are currently dealing with record-high retail electricity prices that are more than five times the average cost of wholesale power. The German government is also considering subsidies to shield its heavy industry from international competition and escalating energy prices. All of these circumstances show an energy system in need of serious reform. Across Europe, the electricity price that end consumers pay comprises the cost of generation, grid expense, government levies, charges, and taxes such as VAT. The approach to taxes and levies varies, with nations including Malta, Bulgaria, and Hungary imposing lighter taxes on electricity than, say, Denmark, which penalizes heavy usage.

The treatment of commercial customers and heavy industry also varies by nation with Germany being highly supportive of manufacturers while Ireland, for instance, is not. All retail electricity prices contain two common elements, however: the cost of electricity generation and maintaining grids.

Price structure

Taking Germany as an example, the average retail consumer paid more than €0.46/kWh ($0.50) in the first half of the year. Those rates were nearly 50% more than what the consumer paid in 2021 and were largely a reflection of the Russian gas crisis. Interestingly, wholesale prices have now come back to 2021 levels of around €0.07/kWh to €0.10/kWh, which begs the question: Why is the German consumer still paying €0.24/kWh just for the generation component of their electricity?

The answer to that question is that they are doing so because many German utilities hedged their power purchases at the top of the market last year, when extreme gas prices and problems in French nuclear saw European power prices hit all-time highs. The good news is that the customer will gain the benefit of the current lower wholesale prices, going forward.

The same cannot be said for the grid costs which make up the other major component of electricity bills. Grid expenses across Europe, as a rule, are lower than generation costs, at an average of €0.06/kWh in the EU. In the first half of 2023, German grid costs were €0.095/kWh, putting them at the very upper end of European costs.

Grid expenses have surged by 50% over the last decade. The substantial investments required to connect new renewables plants and transport their energy, largely account for this trend. Complicating matters, system stability costs are rising exponentially, especially when systems are overloaded or grid bottlenecks occur.

Supply dynamics

Europe currently has an installed renewable energy fleet of 690 GW of generation capacity, comprising 255 GW of hydropower, 225 GW of wind, and 209 GW of solar. On a good weather day, that is enough to meet the electricity needs of the whole of the market. The good news is that there are now many days when 50% or more of Europe’s power needs are met by renewables. If you add nuclear to the mix, there are many days when 75% of Europe’s power needs are met by low-CO₂ electricity. This is particularly the case at weekends, when peak European demand is around 320 GW and there is lots of solar electricity in the system.

This large volume of renewable energy means that the weather now determines the power price. When there is an abundance of sun, wind, and rain – as there was during the first weekend of July – power prices tumble. When there is not a lot of sun or wind, power prices increase. All generators have to monitor the weather so that they can optimize their power generation assets.

The best generation facilities are those that can be easily ramped up and down, like the many types of modern natural-gas plants. When required, the ones that are ramped down first are those with fuel costs, such as coal and gas, especially if a generator believes that they will not be able to recover the costs of fueling their power station with the price they receive on the power market.

The most difficult generation assets to manage are the “baseload” power plants, which are designed for continuous operation. Many old nuclear, coal, and gas power stations are baseload sites, along with most run-of-the-river hydro plants. They are very difficult to ramp up or down, let alone switch off, which is why, oftentimes, they accept very low power prices or even negative prices in the market.

Going forward, the economics of these baseload plants are going to be severely tested as the frequency of negative electricity prices and volatility is only going to rise, fueled by the addition of 70 GW of solar and wind power this year alone, with a similar amount expected next year and the year after. This also poses a financial challenge for new clean energy generation, as renewables plants could potentially also earn zero income during sunny or windy days.

Decarbonization pathways

Rapid decarbonization requires deep electrification of the energy system, starting with transport, then heating, and, eventually, cooling. Major organizations such as the International Energy Agency believe that this is the best route to net zero – not only in terms of economics, but also in order to achieve the goal at a sufficiently fast pace.

The way forward is to add sufficient renewables and nuclear generation to the system to meet growing demand for electricity and to ensure that the electricity mix is clean. This approach has the added benefit of lowering overall energy demand, as the whole process of creating, transporting, and using electricity is much more efficient than burning fossil fuels.

Despite deep electrification being generally recognized as the best way to decarbonize, most countries in Europe still have customer incentive structures in place which are skewed towards the fossil fuel alternatives. In response, governments are finally putting in place subsidies to incentivize customers to buy electric vehicles and install heat pumps.

However, such policies fail to deal with the major distortion present in the market, represented by the fact that it is still cheaper, throughout most of Europe, to fuel a car with diesel than with electricity, or to heat a house with natural gas, as opposed to a heat pump. The main reason for this is tax policies which favor fossil fuels over electricity.

Addressing these challenges requires a multi-faceted approach and will be critical if we are going to decarbonize.

Starter policies

There are six initial policy steps European governments could action:

• Reduce electricity taxation: It is essential to make electrifying transport and heating economically viable for consumers by reducing electricity costs. This will likely involve a fundamental review of what comprises an electricity bill, with a close examination on how best to optimize the generation and grid elements. More importantly, governments need to review taxation policies by noting that in many European countries, taxes represent more than 50% of consumer electricity bills. That level of tax should be progressively placed on fossil fuel in the form of higher carbon levies.
• Use every unit: Wastage of electricity must be minimized by optimizing demand to coincide with periods of surplus electricity and low prices, requiring smart meters and conducive regulation, especially around the provision of flexible tariffs which enable the consumer to take advantage of periods of low electricity prices. It is also important to ensure that regulatory frameworks are in place to allow any excess electricity to be converted into other energy forms, such as synthetic fuels, that will further help with decarbonization. This will also kick-start new business models to benefit consumers and speed up the energy transition.
• Phase out baseload generation: It is necessary to accelerate the phasing out of baseload fossil fuel plants, with the most flexible generation sites being moved into reserve. This will lessen the number of periods with low and negative wholesale power prices which will, in turn, incentivize the building of replacement clean generation facilities while allowing other, cleaner baseload electricity plants – such as nuclear and run-of-the-river hydro – to continue thriving.
• Facilitate energy storage: All barriers to energy storage development should be removed and consideration should be made to putting in place incentives for flexible generation – some of which may be fossil powered – for what German-speakers dub “dunkelflaute” days in winter when there is not enough solar or wind production.
• Accelerate network expansion: Revise the incentive structure for grid operators, in order to push quick and cost-effective investment into power networks while at the same time increasing the utilization and efficiency of existing networks with new technologies and service structures. This will, in turn, unleash a whole range of new business models, from smart charging for electric vehicles to domestic virtual power plants.
• Provide European oversight: Establish a European institution which would be responsible for overseeing the whole energy transition and for ensuring the most effective path forward for the decarbonization of the European energy system. A key focus would be on enabling close, cross-border cooperation, which is key to keeping costs low and which is, in turn, critical for continued European business and industry success as well as keeping the cost of living low for all European citizens.

Without such reforms, the road to decarbonization will be exceedingly rocky. If these measures are implemented, however, they could enable quick, effective, and economical decarbonization.

About the author: Gerard Reid is a partner at corporate finance advisory Alexa Capital. He has spent more than 20 years working in investment banking, equity research, fund management, and corporate finance, with a focus on the energy transition and the digital energy revolution. He previously served as the managing director of European cleantech research at investment banking group Jefferies & Co.

A Brazilian research group has developed a novel recycling method for solar panels that uses supercritical water technology.

Supercritical water is water heated and pressurized beyond its normal boiling point. In this state, it has unique properties that make it a powerful solvent. “The water reaches the supercritical state when the temperature and pressure exceed 374.3 C and 22.1 MPa, respectively. Its physicochemical properties are quite different in this state, promoting the decomposition of hazardous and persistent organic compounds,” the researchers explained, noting that the proposed process does not require toxic or hazardous chemicals.

With the new method, solar cells are first broken into smaller pieces, and placed in a reactor. That reactor is constantly fed with water that is being heated and pressured to a supercritical state. This process results in gaseous, liquid, and solid products.

In order to assess the organic degradation rate of the panels, the academics have tested the method with varied temperatures, flow rates, reaction times, and solution compositions. Then, running a further optimization method, the group achieved a 99.6% organic degradation rate at 550 C, with a reaction time in the reactor of 60 minutes, a volumetric flow rate of 10 mL/m, and a feed solution composed of an aqueous solution of residual organic compound and hydrogen peroxide (H2O2/Rorg).

“The aqueous solution of residual organic compounds, composed of methanol, acetonitrile, and chloroform, was obtained from high-performance liquid chromatography (HPLC) analyses,” they emphasized. “The processing of waste solar panel under supercritical conditions was conducted to evaluate the possibility of the simultaneous treatment of solid waste and organic liquid wastewater, decreasing the amount of clean water consumed.”

Regarding solid products resulting from the method, through the different supercritical conditions, an average metal recovery efficiency of 76% was observed. Among the metals recovered were aluminum, magnesium, copper, and silver. “This recovery possibility makes the process more economically attractive,” they added.

As for the gaseous byproducts, their mean composition using H2O2/Rorg was 72.9% carbon dioxide, 18.6% hydrogen and 8.6% nitrogen. “The obtained results highlight one of the supercritical water technology main advantages, that is, the possibility to use wastewater for the treatment of electronic waste producing only non-harmful gases in a controlled environment,” the scientists stressed.

The liquid byproduct produced in this recycling method mainly consisted of phenolic derivatives such as 3-ethylphenol, bisphenol A, and 4-isopropylphenol. This new byproduct can then undergo another treatment via supercritical water technology, removing almost 100% of the total organic carbon. “This allows the reuse of the liquid outputs in several treatment processes of solar panel waste,” the Brazilian group added.

Finally, the academics have proposed an energy-integrated superstructure design for a scaled-up recycling process. The proposed method for industrial-scale recycling includes a quench unit, flash tank, and fired heater, among other parts. Using simulation software, the scientists found the superstructure to have a 59.2% reduction in the hot utilities requirement and a 60.2% reduction in the cold utilities requirement, compared to a direct scale-up of the experimental setup. In addition, an operating cost reduction of 60.5% was observed.

The proposed approach is presented in the paper “Simultaneous recycling of waste solar panels and treatment of persistent organic compounds via supercritical water technology,” published in Environmental Pollution. It was written by scientists from the State University of Maringá, the Federal University of Goiás, and the University of Sao Paulo.

In the pursuit of a cleaner and more sustainable future, the adoption of EVs has emerged as a significant milestone. Europe is witnessing a surge in EV adoption, driven by the promise of reduced emissions and a greener transportation ecosystem. However a key hurdle remains: the establishment of widespread and accessible EV charging infrastructure. A large share of Europeans live in multi-apartment complexes where the installation of charging facilities is far from straightforward.

While EV charging set-ups are relatively uncomplicated for residents of detached houses, people in multi-unit complexes face a more intricate scenario. Multi-home buildings often have car parks that can accommodate many vehicles and even if there are only a few EVs right now, it is important to get a scalable infrastructure in place from the start so that more drivers can be added over time. The need for system charging – where chargers work together to optimize energy distribution – combined with the management oversight provided by a charge-point management system (CPMS), adds further complexity to the equation.

At Elaway, we recognize a substantial barrier to progress regarding financing of the fundamental charging infrastructure needed for system charging in housing communities. This obstacle poses a chicken-and-egg dilemma. Without adequate infrastructure, EV adoption rates may stagnate as residents lack the convenience of home charging – one of the primary advantages of EV ownership. With only a small percentage of today’s EV owners living in housing communities, however, willingness to contribute to finance charging infrastructure remains limited. It can be a self-perpetuating cycle. Most residents who drive fossil-fuelled cars are unwilling to pay for EV infrastructure. With almost half of Europe's population living in multi-apartment complexes – according to EU statistical body Eurostat – appropriate charging infrastructure is a major challenge that needs to be addressed to ensure the uptake of EVs by people in such buildings.

A successful model can be observed in Norway, a leader in the EV market. The Norwegian EV Association estimates electric vehicles have a market share of more than 80% of new cars sold and EVs now make up more than 20% of the total car fleet. The success is, in part, because Norway has pioneered a solution to the financing challenge. The Nordic state has mandatory regulations for housing communities to provide EV charging, coupled with a stipulation that entire communities share the financial responsibility for charging infrastructure. This proactive approach has propelled the swift expansion of EV charging facilities in multi-home communities.

Addressing this intricate challenge necessitates innovative solutions and external catalysts. This is where EU legislators can play a transformative role. By introducing incentives and progressive regulations, they can facilitate the development of EV charging infrastructure in housing communities.

Elaway has been providing EV charging solutions for housing communities in Norway since 2019 and is now one of the leading players in this segment of the Norwegian market, which is a few years ahead of all other European countries. We have experimented with different business models to test what creates traction in the market and our experience is that offering apartment communities the opportunity to rent charging facilities significantly lowers the finance barrier. Elaway's approach to incentivizing charging infrastructure installation showcases a promising path forward. Our model offers customers the flexibility to purchase or rent charging facilities, catering to a wider spectrum of financial situations. This creative financing solution could act as a catalyst, encouraging more multi-home communities to embark on the EV charging journey.

To address the EV charging challenge legislatively, EU policymakers could focus on the following strategies.

Infrastructure-focused incentives: Shifting the focus of incentives from individual chargers or vehicles to charging infrastructure could inspire multi-home communities to invest collectively, acknowledging the collective benefits for all residents.

Mandatory EV charging provision: Copying Norway's approach and mandating housing communities to offer EV charging could accelerate the roll-out of charging facilities in housing communities across Europe.

Community-funded installation: Introducing policies that ensure entire housing communities contribute to financing installation, rather than relying on a small subset of early adopters, would secure sufficient funds and establish a fair and sustainable model for EV charging expansion in such communities.

Incentivizing infrastructure ownership and renting: Recognizing the varying financial capacity of multi-apartment communities, EU policymakers could extend incentives to both owned and rented charging infrastructure, accommodating diverse financial scenarios.

Aligning policies with the recommendations above, the EU could emerge as a driving force behind the accelerated deployment of EV charging infrastructure in multi-home communities. Legislative endeavors have the potential to bridge the financing gap, surmounting the challenge of limited EV adoption that is being hampered by inadequate charging facilities. A concerted effort could pave the way for a harmonious environment where electric mobility flourishes, emissions dwindle, and a sustainable future becomes a tangible reality.

At Elaway, we firmly believe that by uniting industry players and policymakers, we can steer Europe towards a future powered by clean and efficient transportation.

About the author: Harald Seip is chief marketing officer at Elaway, a company that provides EV charging solutions for housing communities in Norway, Sweden, and Germany. He oversees marketing for a company that has more than 1,100 charging stations, more than 75,000 parking spaces, and more than 10,000 active chargers in its portfolio.

Sodium-ion batteries have attracted extensive attention for their advantages over ubiquitous lithium-ion technology, including low-cost raw materials, improved safety, fast charging capabilities, and low temperature performance. With the technology on the cusp of commercialization, the search for electrode materials with high electrochemical performance is ongoing and hard carbon is emerging as the most promising anode material.

Now, a new research paper authored by scientists from Fuzhou University in China and the University of Macau has summarized the challenges as well as the perspectives on the future of hard carbon.

The researchers note that the commercialization of hard carbon still faces technical issues of low initial Coulombic efficiency, poor rate performance, and insufficient cycling stability, due to the intrinsically irregular microstructure of hard carbon.

“To address these challenges, the rational design of the hard carbon microstructure is crucial for achieving high-performance sodium-ion batteries, via gaining an in-depth understanding of its structure–performance correlations,” they write.

Furthermore, their review looks into a range of research studies brought about by the emergence of hard carbon electrodes, covering in the process the sodium storage mechanism of hard carbon electrodes, the selection of hard carbon precursors, electrolyte matching engineering, and the requirements for practical commercial engineering.

The researchers highlight the importance of precursor selection with most hard carbon electrode precursors derived from biomass materials and industrial product derivatives, such as cellulose, ginkgo leaf, glucose, cotton, resin, sucrose, or glucose. “The selection of low-cost, scalable precursors has become a key factor affecting hard carbon’s commercialization,” they write.

Their review also considers various sodium storage mechanisms, such as the insertion–nanopore filling model, absorption-insertion model, absorption-nanopore filling model, or absorption-insertion nanopore filling model, which can yield hard carbon materials with different properties.

In addition, the researchers underline the importance of matching the hard carbon electrode with the right electrolyte as an important factor for the electrochemical performance of the batteries. They note that ester electrolytes are a poor match with hard carbon, and therefore the search for high-voltage ester electrolytes should be a priority.

“In the future, determining how to construct high-performance hard carbon to achieve practical commercial applications of sodium-ion batteries is crucial, and this will require a thorough understanding of the real sodium-ion storage mechanism, hard carbon preparation and precursor selection, and electrolyte regulation,” the researchers write.

Finally, the paper highlights directions for the future development of hard carbon to achieve the commercialization of high-performance sodium-ion batteries.

This includes further study of the mechanism of hard carbon sodium storage to help improve the electrochemical performance of hard carbon electrodes, further improvement of their electrochemical performance, development of precursor materials with low cost, low energy consumption, and high carbon yield, and those derived from industrial waste product material, as well as presodiation treatments that can ensure high Coulombic efficiency and optimize the energy density of the battery.

“While the emergence of hard carbon electrodes has indeed promoted the commercialization of sodium-ion batteries, more work is still needed to make commercialization a reality, the researchers write in the paper titled “Revitalizing sodium-ion batteries via controllable microstructures and advanced electrolytes for hard carbon,” published in eScience.

When planning for change in the decades ahead, Western utility companies could learn much from the experience of competitors active in emerging markets, as well as from business units of their own based in such regions. While it is intuitive to think corporates in the world’s most advanced economies will always have first-mover advantage, and be able to rely on the latest technology, such assumptions may ultimately lead to them falling behind their developing-world peers.

There are several reasons why Western companies cannot afford to be complacent. Firstly, developed markets can be prone to sticking rigidly with longstanding infrastructure which is typically complex and expensive to change. As a result, modest improvements and updates are likely to be preferred over wholesale change and the introduction of new systems.

The rollout of new infrastructure may also face democratic and bureaucratic resistance, as well as regulatory inertia – even if it offers obvious gains. For example, the resistance to building new railways is entrenched in Britain and almost impossible to overcome, with costs spiralling out of control, as England’s beleaguered HS2 high-speed rail project is demonstrating. Such opposition is present despite  the fact the country's economy was historically revolutionized towards the building of large-scale railways.

Developed markets may also carry a bureaucratic burden that discourages business model evolution. By contrast, less-regulated emerging markets can foster flexible and dynamic business models, adaptable to regulatory change and market disruption. That is why disruptive technology and new approaches tend to have the best chance of getting off the ground in emerging markets.

Less bureaucracy

While technology is often developed in the Western engineering labs of academia or industry, emerging-market utilities face fewer bureaucratic obstacles to adoption, which means it is easier to carry out large-scale testing and faster to learn the necessary lessons.

This flexibility has enabled emerging markets to leapfrog traditional utility models in some instances. The adoption of microgrids and off-grid renewable energy plants in sub-Saharan Africa, for example, demonstrates the efficiency of decentralized power generation. Flexibility encourages the rapid proliferation of new systems and methods, whereas this would be inhibited in developed markets by the large-scale investment required to change legacy infrastructure.

Another advantage of emerging markets is the widespread adoption of internet and smartphone technology. In the context of utilities, this means emerging markets can generally offer the necessary networks for monitoring energy usage, making payments, and implementing real-time communication with utility providers. This offers lessons in business operation and, crucially, consumer engagement.

It is no surprise that renewable energy technology’s increasing affordability in emerging markets is fuelling a “prosumer” trend – with people not just consuming energy but also producing it, and selling any surplus back to the grid.

Utilities in emerging markets have shown the effectiveness of incentive programs such as demand-response and time-of-use tariffs with their use in incentivizing prosumer participation, balancing the grid load, and promoting energy efficiency.

Smart appliances with artificial intelligence capability are hugely exciting, as models learn and adapt to consumption habits in markets across the world, from Egypt and Brazil to the Philippines, then respond to price signals. These smart grids allow for two-way communication between utilities and consumers, enabling a dynamic, interactive energy ecosystem and better grid management.

In such fragmented and diverse markets, the need for interoperability is very clear. At Pylon, we have developed a hardware-agnostic infrastructure management platform which can integrate as many as 26 different metering models and enable utility companies to monitor usage, detect losses, and improve revenue in real time.

This approach demonstrates how emerging market utilities can leapfrog well-established competitors, providing a blueprint for the future. Similar lessons, regarding subscription models to supply affordable metering infrastructure, could be useful for Western utilities, particularly as high inflation makes consumers in developed markets acutely aware of costs.

Lessons

For Western utilities, emerging market innovation should provide insight into the changes needed to work in unfamiliar conditions, as well as the opportunities and limits offered by smart grids. Both can ensure further development is adjusted, to make adoption in developed markets as seamless as possible.

The lesson is that distributed-generation, coupled with energy storage, can provide reliable, sustainable power, even in remote locations. It is a necessary example for many markets, particularly given the execution challenges of widespread renewable power installation.

Likewise, utility companies can play a crucial role in enabling and managing virtual power plants. These offer services similar to traditional power plants but with greater flexibility and lower environmental impact.

It is said that necessity is the mother of invention and this is particularly true for utilities in emerging markets. Time after time, these companies develop and apply new, technology-based solutions in often inhospitable environments. Their successes and setbacks could offer vital lessons for Western utilities over the coming years.

About the author: Ahmed Ashour is the co-founder and CEO of Pylon, the utilities management platform transforming water and electricity companies in emerging markets. Ahmed plays a crucial role in driving the efficiency of utilities and helping to save the planet, one smart metering point at a time.

From pv magazine 07-08/23

European funds have been pledged to back two solar and energy storage solutions to help smallholders in Africa till tough terrain and get produce to market. London-based impact investor InfraCo Africa will spend $2 million to acquire 40% of Mobility for Africa, a Harare business which adapts Chinese-made electric tricycles to bring mobility to remote areas of eastern Zimbabwe, and United Kingdom government body Innovate UK is funding a GBP 270,000 ($336,000) pilot project which could transform farming in Malawi.

US-born Mobility for Africa boss Shantha Bloemen tells pv magazine the accelerated roll-out of her company’s Hamba tricycles could have a huge impact on communities, and particularly on women who take produce to market.

“Africa is still primarily a rural continent, something like 70%, on average,” says Bloemen, who co-founded Mobility for Africa four years ago in Harare, alongside the late Felicity Tawengwa. “There’s a huge deficit of roads – concrete, tarred roads – and also a deficit of transport, and that becomes more acute the further you go away from a road. The World Bank says something like 40% of the rural population live at least 2 km from a major road.

“Even if you have a really good harvest and grow lots of tomatoes, it’s going to be very difficult to get those to market. Women die in childbirth because they can’t get to a rural health clinic, children are not vaccinated for the same reason. Women spend three hours walking to get water, that’s time that could be used to grow more tomatoes.

E-transport

“It’s something anyone who has spent time in rural parts of the continent can see,” adds Bloemen. “We have a romanticized view of women balancing big baskets or a baby on their heads and we’ve come to accept that as normal.”

Electric transport could change the picture, says Bloemen, who grew up in Australia and retains the accent.

She says, “The exciting thing is, now we have the potential of electric transport and we can’t justify ignoring such a lack of facilities any more. Petrol is often imported; it’s expensive, and it relies on a big company to distribute so it’s rarely available in rural areas in practical quantities. When we were reliant on fossil fuels [for transport] it was left as something that was impossible to solve.”

The Mobility for Africa director and CEO says she came up with the idea of importing tricycles – christened Hambas, from the Ndebele word for “go” – to Zimbabwe after seeing them widely used in China, where she worked for UNICEF, formerly known as the United Nations International Children’s Emergency Fund.

The tricycles are manufactured by Ducar and went electric, powered by a lead-acid battery, eight years ago.

Mobility for Africa crowdfunded a container of 50 vehicles and deployed them with the help of students from China and Zimbabwe and two Ducar technicians. Assembling the Hambas locally, the company found the long charging times necessary meant lead-acid batteries were impractical. Although a consignment of off-the-shelf lithium-ion batteries brought further range, Bloemen says, “we could see they were more suited to [energy] storage than to transport.”

Bespoke batteries

Help arrived from former Tesla engineer Ruichen Zhao, whose Fourier Energy startup designed a bespoke 5 kW lithium phosphate battery which offers a 100 km-plus range under a 300 kg to 400 kg load. “It should last 8,000 to 10,000 cycles, which is something we’re testing – so that should be good for at least 40,000 km,” says Bloemen.

With the Hambas fit-for-purpose and modified to make them more comfortable for women to operate, Mobility for Africa needed an optimal deployment plan.

“We’ve been testing, for three years, a fleet management system for shared mobility,” says Bloemen. “Our model is based on introducing a fleet of tricycles designed for women, setting up a system of battery swapping, using off-grid energy, and you then use shared ownership models with groups of women renting the tricycles – now with, also, a lease-to-purchase model – on a monthly basis.

“We also have drivers servicing rural transport needs: transporting an elderly woman to a clinic, perhaps, or taking produce to market.”

Mobility for Africa tackles the recharging challenge by charging a fee to swap a battery. Additionally, it offers a “mobility-as-a-service” model, for groups to rent the tricycles on a monthly basis.

InfraCo cash

The $2 million equity investment from InfraCo Africa – which is funded by the governments of the Netherlands, Switzerland, and the UK – will turbocharge the number of Hambas and charging stations deployed by a company, which has locations at Harare and Domboshawa; a pilot site at Wedza, 140 km from Harare; and which set up a base, last year, at Chipinge, a mountainous dairy farming area 600 km from Harare.

With Mobility for Africa assembling four Hambas per day – Bloemen’s aim is to eventually have a factory in Zimbabwe. The company had a fleet of 200 vehicles at the time of writing and is due a further 200, spread evenly across its four sites, in August, and the same number again by March, to unlock the full InfraCo Africa investment. The intent is to fund 600 extra batteries, in addition to the Hambas, plus eight new solar-powered charging and battery swapping stations. Mobility for Africa’s [MFA] charging station at Wedza has 15 kW of rooftop solar generation capacity.

“MFA’s offering has the potential to deliver very high sustainable development impact, enabling increased trade in agricultural produce, creating employment, promoting economic growth, and easing movement in areas with difficult terrain,” an InfraCo spokesperson tells pv magazine.

Mobility for Africa is exploring how the charging stations and batteries which power the Hambas can offer electricity to rural communities, an aspect the project has in common with the AfTrak farming pilot scheme in regional neighbor Malawi.

Engineers from Loughborough University, in England, and US-based lead-acid industry body the Consortium for Battery Innovation (CBI) believe they have a sustainable method of providing the “deep bed farming” needed to cultivate the impermeable subsoil present in much of Malawi.

Project partner Tiyeni, a UK-based non-governmental organization, identified the increased agricultural yields available if small scale farmers could successfully till the “hard pan” ground that is around 300 mm below the topsoil in many areas of the African nation.

Loughborough University’s Jonathan Wilson and CBI representative and project manager Carl Telford came up with the idea of converting a hand-steered tractor unit to be powered by heavy, lead-acid truck batteries.

Eureka moment

“Jonathan Wilson and I went to Malawi with Innovate UK to learn about energy issues in the country,” says Telford. “We came up with the idea for the Aftrak.”

Taking its name from “Africa Tractor,” the AfTrak will feature four 12 V, 210 Ah batteries supplied by Swiss-owned manufacturer Clarios. Wilson tells pv magazine the AfTrak batteries will offer 6 kWh to 8 kWh of usable capacity.

The two tilling devices to be funded by the pilot program will be charged from a base station fitted with 3 kW of solar generation capacity which, Wilson says, will generate around 15 kWh to 18 kWh of clean power per day. Each AfTrak will also have a 200 W panel which will generate approximately 1 kWh daily, for top-up purposes. Clarios will donate the batteries for the first two AfTraks.

The modular base stations feature 1 kW solar capacities which can be stacked to meet local needs and can provide clean energy for communities and function as a microgrid if needed, Wilson adds.

Project manager Telford says the AfTrak could find much wider use, citing neighboring Zambia, which has similar farming issues.

“If it proves successful, there could be other agricultural challenges we could use the basic system for, perhaps by changing the shape of the tilling tool. The part that does the tilling is typically made of a hard material so we’re making them replaceable with steel, and potentially with locally fabricated materials.”

Lead-acid

The CBI representative explains why the Aftrak features lead-acid, rather than lithium-ion batteries.

“Lead-acid batteries have a very high recycling rate,” says Telford, “by teaming up with Varta [German battery maker Vertrieb, Aufladung, Reparatur transportabler Akkumulatoren], the recycling rates of lead-acid batteries are incredible. The main thing is they’re so robust, so stable, and so easy to use – they’re abuse-tolerant. In the environment where we’re using them, they’re a better choice. They are also a lot cheaper than lithium-ion batteries.”

Mobility for Africa Chief Executive Bloemen also has high hopes for the wider use of her company’s electric Hambas, beyond rural Zimbabwe.

“Kenya and Zambia have similar ideas about community farming and agricultural development,” she says. “I do think this is a new focus in Africa because small-scale farmers are the backbone of African food production. If we can make the right strategic partnerships, we can come in and provide the mobility solutions.” Mobility for Africa’s pitch to InfraCo Africa cited potential markets in Benin, Malawi, Mozambique, Nigeria, and Zambia.

The company has already supplied vehicles to local police and health services.

“We’ve tested our tricycles with rural healthcare facilities and now we’re asking whether we can try a pilot program at, say, 50 clinics, especially when they’re already installing solar for cold-chain purposes,” says Bloemen.

She says the InfraCo Africa funding is a transformational development.

“We have been managing on grants,” she tells pv magazine. “$1.5 million of Swiss money, another grant of Swedish money but they all need matching funds. We were in what the startup community calls the ‘valley of death’ – where a company has to transition from family and friends – and crowdfunding – to really scaling. Two million dollars is a small-ticket item for InfraCo Africa but, for us, we now have a year to prove this can be financially viable and have a real impact and then, hopefully, we can grow to where I can put a proper factory in place and expand internationally.”

A new study published by Greenpeace found widespread use of misleading numbers and strategies in reporting on emissions and climate impacts among 12 of the largest oil companies with headquarters in Europe.

The study, titled Dirty Dozen: The climate greenwashing of 12 European Oil Companies, looks into financial statements published by six of the world’s largest oil companies – Shell, TotalEnergies, BP, Equinor, Eni, Repsol, and another six smaller players that still play a major role in the energy supply of their respective European markets – OMV, PKN Orlen, MOL Group, Wintershall Dea, Petrol Group, Ina Croatia.

These companies have enjoyed huge revenues over the past year, with their 2022 profits increasing by an average of 75% over the previous year. Despite this, new investments made by the companies increased on average by just over half that amount – 37%. And 92.7% of these investments were made in the continued extraction of fossil oil and gas.

This comes in spite of the common claim among large fossil fuel companies that higher profits are necessary to provide the means to finance a transition to renewable energy, which Greenpeace describes as “like eating more to have the energy for the diet.”

All 12 of the companies in the studies produced at least 98% of their energy in 2022 from fossil fuels, with an average of just 0.3% from renewable sources. And those which are making any investment in “low carbon” technologies are focused on offsetting and carbon capture – two strategies whose effectiveness in reducing emissions is in serious doubt.

No net zero

The study also finds that while most of the companies involved have made a public commitment to reach net zero emissions by 2050, none has anything resembling a coherent strategy in place to achieve this.

“…no major oil company can show a comprehensible plan for a “net zero” in 2050. There is, if at all, a slow start in the 2020s, which is then miraculously supposed to lead to a rapid transformation after 2030. In other words, the solution to the climate problem is postponed to the future or to the next CEO,” the report stated.

The report also noted a range of strategies used by some of the 12 companies that seem designed to mislead the public over their commitment to emissions reduction. From creative definitions of what constitutes “low carbon” for investment, to simply misleading visual layouts – such as Shell placing “conventional fuels” in fourth place on a list of its energy portfolio, despite these accounting for more than 90% of its energy production.

Comprehensive strategy

Greenpeace calls for various measures to be put in place to change this situation, placing efforts to reduce demand for fossil fuels at the center of its proposal. “Similar to the coal sector, the focus should therefore be on a rapid economic and political downsizing of the oil and gas sector, on skimming profits, avoiding stranded assets and, above all, on a rapid reduction of oil and gas demand,” they state.

The report calls for a comprehensive demand reduction strategy to be put in place at EU level, including a ban on short distance flights and promotion of zero-carbon fuels in long distance aviation, noting that “The benefits of these new fuels must be independently confirmed in a life-cycle approach in order to exclude, for example, the use of biofuels, which can cause high climate damage along their production chain.”

Other industries earmarked for action include marine shipping – which also requires support for alternative clean fuels, and the petrochemical industry which should see restrictions on per capita consumption of plastic materials.

Greenpeace also states that, in combination with demand reduction, these measures can be accompanied supply side measures such as windfall tax on profits, a ranking of the most environmentally damaging fossil fuel supply chains, and a stop on exploration of new oil projects across EU territories and the North Sea.

Further, the report calls for increased regulations on international oil companies, including a general ban on advertising and much tighter reporting definitions to address greenwashing in public statements.

From pv magazine 07-08/23

Renewables are increasingly the answer to Ukraine’s energy woes. Widespread blackouts last fall and winter triggered a solar boom in the country, as households and businesses struggled to find solar-charged batteries. The solar frenzy heralded humanitarian programs, primarily focused on keeping the lights on for the critical civil infrastructure: schools, hospitals, and kindergartens.

Solar, as the most easily deployed clean energy source, can support Ukraine in its hour of need, says Máté Heisz, director of global affairs at industry group SolarPower Europe. “Ukrainian people continue to live in fear and feel the daily effects of the attacks on their homes, hospitals, and schools,” he tells pv magazine.

SolarPower Europe, Bundesverband Solarwirtschaft (BSW), and its Ukrainian PV industry association peer launched the “Solar Supports Ukraine” campaign in December 2022 to support critical infrastructure in the wake of constant, prolonged outages.

SolarPower Europe member BayWa r.e. has made a generous donation to fund a solar project to meet all the power needs of Kharkiv Hospital No.17. The German developer is due to work with campaign implementation partner the RePower Ukraine Foundation, on the project.

“Energy Act for Ukraine Foundation and Menlo Electric will also jointly develop a solar and storage installation for the Bucha, Lyceum No. 3 school, one of the projects which we are fundraising for,” says Heisz. “The two organizations will equip up to 10 Ukrainian hospitals and schools with solar, with a total output of 300 kW.”

That solar system was financed by donations from BSW members including SMA, Qcells, BayWa r.e., and IBC Solar. “Despite the substantial amount we have received, we are still relentlessly pursuing more corporate donations,” says Heisz. “In particular, we are still missing about €40,000 ($43,600) for our next project, the Chernihiv Regional Hospital Project. With this money, our implementation partner, the Energy Act for Ukraine Foundation, would be able to construct a 73.6 kW hybrid solar system which will partially cover the hospital’s electricity supply and, critically, its surgery and intensive care units, where lifesaving work is being performed.”

Heisz highlights the recent destruction of the Nova Kakhovka dam and hydroelectric power station in Kherson which forced thousands to evacuate, and halted access to electricity. “That’s why we are still asking people to donate to our Solar Supports Ukraine campaign and to help keep the lights on in Ukraine,” he says.

Making a difference

Other solar aid initiatives also focus on critical infrastructure. “The last heating season, in the midst of a full-scale war, showed how important it is for hospitals and water utilities to have their own sources of electricity,” says Dmitro Sakhalyuk, technical expert of the Solar Aid for Ukraine initiative and for NGO Ecoclub.

As of June, the initiative was completing three solar plants for hospitals in Dubno, Zhytomyr, and Sumy. “We have developed design and estimate documents and will soon announce tenders for the construction of solar plants for water utilities in Zviahel, Zhytomyr region; and Brody, Lviv region,” says Sakhalyuk. “In addition, in Kremenchuk, where we plan to build a solar power plant for a hospital, we will soon develop design and estimate documentation. In less than a month, we will start constructing three more solar power plants.”

Ecoclub has received more than 200 requests for solar plants from Ukrainian municipalities and the number keeps growing. “We are looking for partners who will provide equipment, implement turnkey projects, or finance them,” Sakhalyuk says, adding the immediate target is to bring 118 kW of equipment from Europe with negotiations ongoing for twice that generation capacity.

Solar Aid for Ukraine aims to show renewables are affordable and to encourage communities to work towards energy independence. The government last year outlined ambitious clean power targets in its national recovery plan. Solar should play a vital role in a plan many say should be instituted immediately.

“Ukraine’s post-war sustainable recovery has already begun,” says Sakhalyuk. “So it is the best time for international partners to cooperate with Ukrainian municipalities and explore different models of financing clean energy projects.”

Pumping in cash is not the only solution, Sakhalyuk adds. “Municipalities in Ukraine need capacity-building assistance,” he says. “By working together with international partners, local officials and experts can learn from international experience, gain new skills, and enhance their knowledge in various areas including governance, urban planning, and economic development. Such cooperation will help Ukraine accelerate its recovery process.”

Olena Koltyk, head of the Ukraine Support Team (UST), tells pv magazine, “Ukraine definitely needs more solar aid as the country has great potential for it – especially in southeast regions which are severely suffering because of war – to make them resilient. Moreover, it has to be not only the donations of equipment but help with devising technical projects and installation, because communities do not have the capacity and expertise.”

UST works to equip hospitals, schools, and other critical infrastructure with hybrid solar. “Installation of solar is more reasonable in Mykolaiv than in Chernihiv region, due to better insolation,” says Koltyk. “In addition to hybrid solar plants, it makes sense to install solar collectors for hot water and heat supply. At the moment, we are looking for donors to finance these projects. Several projects on the installation of solar in hospitals and schools have already been implemented in Ukraine but this is extremely insufficient – there may be thousands of such projects.”

Taming chaos

International solar aid for Ukraine is chaotic, however. No one knows where solar panels and batteries are going so it is not clear how effective they will be, says Oleksiy Orzhel, chairman of the Ukrainian renewable energy association. Orzhel stresses, though, how grateful Ukrainians are for the aid.

The nation needs systematic aid for industry with Orzhel stating there is practically none. Guarantees to foreign investors are not being fulfilled, he says.

This “calls into question the future development of the market,” says Orzhel. “In this regard, there are ideas for foreign donors and investors to finance a fund that would provide a certain level of guaranteed payments for investors in renewable energy facilities. Such a tool would partially allow them to pay off loans, cover operating costs and costs of repair and restoration after emergency modes of the grid.”

Historic international programs to support industry have been halted by the war. A Ukraine Recovery Conference held in London in June discussed insuring such programs but it is premature to discuss action, says Orzhel.

Humanitarian aid from the EU and its member states to fund autonomous solar plants in areas where the grid has been disabled is seen as a temporary or medium-term solution. Such projects are combined installations enabling a hospital, school, or administrative building to have electricity, at least during daylight hours.

“At the moment, at the level of certain tasks and strategies, the possibility of investing in decentralized renewables generation is being considered,” says Orzhel. “At the same time, in connection with the constant military operations – and every day the Ukrainian energy industry is under fire – there is no investment in the energy sector.”

Supporting household solar is attractive since it brings visible results at a minimal cost. A rooftop solar panel installed at the hospital could save patient lives during outages every day. Helping with the development of the industrial sector is a more long-term strategy, requiring substantial funds and effort, but it could eventually become a game changer for the country’s energy security.

*Currency translation made on 21/08/23.

From pv magazine 07-08/23

China has dominated the solar module supply chain for the last 15 years but the status quo is shifting as multiple emerging factors pose a threat to the nation’s dominant position. These include increasing scrutiny of solar supply chain sustainability and traceability along with a growing global subsidy race, with the United States, India, and European Union announcing plans to provide funding support to their own manufacturers.

A suite of policy levers has recently been used by global markets to support the growth of domestic PV manufacturing directly and indirectly, including the Inflation Reduction Act in the US and the Basic Customs Duty and Production Linked Incentive scheme in India.

At the policy level, Europe is lagging. The REpowerEU initiative sets ambitious 2030 targets for renewables but does not say much about supporting local manufacturing. The recent Net Zero Industry Act (NZIA) proposal aims to spur local manufacturing. While that is a step ahead, it could take up to two years before the European Commission approves the policy. In other words, the European Union has set very ambitious targets for renewables installations in Europe until 2030 but such targets will not automatically increase demand for products manufactured locally.

US contrast

The United States is ahead in timing and financial support so US incentives have the potential to become a risk for European manufacturing to scale up as the country is already pulling investment resources from major players. That risk increases the longer it takes to get EU policy and incentives firmed up.

To provide some context, the EU is targeting a minimum of 45% self-sufficiency across all manufacturing nodes despite the fact there is currently almost no ingot or wafer capacity to process polysilicon in Europe. It would require the building of more than 40 GW of annual ingot, wafer, and cell capacity – plus another 30 GW of module capacity – to reach these targets. To have any chance to get anywhere near this ambitious target, the European Union would need to introduce a combination of high manufacturing incentives and barriers of entry for lower-cost imports (such as its proposed carbon border adjustment mechanism to punish products with higher carbon footprints) as well as potentially setting quotas for local content in public tenders.

Cost gap

The large production cost gap between regions is the biggest challenge to overcome to spur local module supply chain manufacturing. A recent S&P Global Commodity Insights report revealed production costs in Europe could be as much as 50% higher than in mainland China – mostly thanks to higher EU power prices and labor costs.

The recent low-price module environment could become another unexpected hurdle to the reshoring of European module supply chains. High polysilicon prices have kept module costs elevated in the last two years, closing the gap between best-cost manufacturing locations in mainland China, Southeast Asia, and other regions (including Europe and the US). If the anticipated low module prices return, it will make onshoring module supply chain manufacturing increasingly challenging.

Local manufacturers could be competitive in other dimensions, however. European module production costs are higher compared with other regions but may hold advantages due to a reduced carbon intensity of the end products. This sustainability dimension will be particularly relevant given the current trend to tax imported materials and components with higher carbon footprints. European governments could also set quotas for locally-made, low-carbon content in public tenders – the current NZIA proposal includes a clause related to carbon footprint and equipment origin for public tenders plus a 15% to 20% sustainability and resilience weight-scoring system.

Another dimension where EU manufacturers can be competitive concerns technology. There are opportunities for EU manufacturers to lead the development of new technology such as perovskites or new wafer technologies with lower cost production methods and higher efficiencies. Partnerships have emerged in several European markets aiming to commercialize next-generation cells and modules based on silicon-perovskite tandem technology. These ongoing research partnerships could promote European technological leadership across emerging cell and wafer technology, enabling a lower levelized cost of energy and reduced supply-chain risk.

Despite all the policy uncertainty, there were around 20 GW of module manufacturing capacity announcements in Europe to May plus a surge of new announcements in the last few weeks. These figures show evidence of new manufacturing activity in markets including Romania, Germany, France, and Italy. Even if all these announcements come online, however, Europe would still be highly dependent on imported cells from mainland China or Southeast Asian countries.

Recent discussions at the Intersolar Europe exhibition confirmed this view. Few among the main industry stakeholders (developers, utilities, investors, supply-chain companies) expect any major reshoring of module supply chain capacity in the next few years. The general industry view is that the European Union will prioritize the achievement of ambitious renewables deployment targets to 2030, ahead of reshoring-manufacturing ambitions that would make the energy transition more expensive.

About the author: Edurne Zoco is an executive director in the Clean Energy Technology group at S&P Commodity Insights. She leads research across solar PV, supply chains, and carbon sequestration. She has been involved in the PV industry for more than a decade and has written cost-breakdown models, company benchmarking reports, price forecasts, supply chain analysis, and technology outlooks. She has presented at major industry events and conferences since 2007 and her commentary and analysis appear regularly in industry reports and mainstream media outlets. Zoco holds a PhD from the University of Notre Dame in the US.

China will set up a recycling system for ageing wind turbines and solar panels, drawing up new industrial standards and rules to decommission, dismantle, and recycle wind and solar facilities, the National Development and Reform Commission (NDRC) and five other state agencies said on Thursday. The state planning agency said that China would have a “basically mature” full-process recycling system for wind turbines and solar panels by the end of the decade.

China’s new energy sector, which covers wind, solar, battery, and other emerging energy technologies, will face a problem of “mass decommissioning of equipment” as industry upgrades accelerate, the state agencies said. The country is set to retire about 250 GW of solar panels and 280 GW of wind turbines by 2040, according to Greenpeace.

Recycling has emerged as a pivotal element in forging a circular economy within the photovoltaic (PV) industry, enabling a sustainable and resource-efficient future. While the durability of PV modules presents a challenge for recycling efforts, a novel solution has surfaced in the form of the Hot Knife method. Collaborating with a leading technology manufacturer, Task 12 of the International Energy Agency's Photovoltaic Power Systems Programme (IEA PVPS) has released a new report, offering a comprehensive environmental life cycle assessment of this innovative PV recycling technique.

Recycling: A Cornerstone of Circular Economy for PV

As the number of decommissioned PV modules increases, the responsible management of end-of-life modules becomes essential to minimize waste and maximize resource recovery. Recycling not only conserves valuable materials but also significantly reduces the industry's environmental footprint, making it a critical driver of sustainable growth.

PV modules are engineered to withstand harsh environmental conditions for decades, showcasing the robustness and longevity of these devices. However, this very durability creates challenges in the recycling process. Among the most formidable obstacles is the intricate task of separating the glass from other layers of the module. Traditional recycling methods often struggle to efficiently and economically delaminate PV modules, necessitating a different approach.

Introducing the Hot Knife Method: A Novel Solution

The Hot Knife method stands out as a cutting-edge and innovative solution to the delamination challenge. By utilizing thermal treatment, this novel technique melts the polymers that bind the glass to the ‘cells/Ethylene-vinyl acetate (EVA)’ backsheet, facilitating the separation process. Preliminary treatment steps also achieve the removal of the junction box, cables and aluminum frames. The materials that can efficiently be recovered are aluminum and glass sheets, as opposed to contaminated crushed glass, which is the product of other recycling techniques.  Other components sold for further treatment/recovery include the copper cables and cells/EVA backsheets. As a result, the Hot Knife method not only streamlines recycling efforts but also demonstrates the potential to significantly reduce energy consumption and greenhouse gas emissions associated with recycling.

IEA PVPS Task 12 Collaboration: Assessing the life cycle related environmental impacts

Recycling processes are most valuable if their contribution to the overall system environmental footprint is low. IEA PVPS Task 12, in collaboration with a prominent PV technology manufacturer, embarked on the journey to assess the environmental impact of the Hot Knife method.

The report “Life Cycle Assessment of Crystalline Silicon Photovoltaic Module Delamination with Hot Knife Technology” delves into the comprehensive scope of life cycle assessment, encompassing all stages of the Hot Knife recycling process. From material extraction to module manufacturing, usage, and eventual recycling, the LCA offers a holistic evaluation of the environmental impacts associated with the Hot Knife method. The environmental impacts caused by the delamination process are attributed to the materials recovered and compared to the environmental impacts caused if these materials were produced from primary resources.

The findings of the report underscore the impressive environmental efficiency of the Hot Knife method. It efficiently recovers aluminum and glass and separates the backsheet (containing cells/Ethylene-vinyl acetate (EVA)). Based on measured data from the manufacturer, the use of this technology contributes 0.3% or less to the life cycle related environmental footprint of PV electricity in any impact category. Additionally, compared to the environmental impacts of virgin materials, the environmental impacts of recovered materials are lower by 80-98% depending on the impact category. Notably, the recycling process significantly reduces energy consumption, greenhouse gas emissions, and the overall environmental footprint compared to corresponding primary materials. Additionally, the recovery of valuable materials highlights the potential for greater resource efficiency within the PV industry.

Due to the high environmental efficiency, the technology is now being used in one of the largest commercial scale PV recycling facilities in the world (by ENVIE in Saint Loubès, France), as well as some facilities in Japan. Through this early experience, further improvements, such as gains in energy and consumables efficiency are to be expected as this technology is deployed in other applications and upscaled to larger volumes.

Conclusion

As we strive to build a cleaner, greener future, embracing PV recycling emerges as a fundamental pillar in the transition towards a sustainable energy landscape. As proven by the Task 12 report, the Hot Knife method represents an innovative approach to address the challenges of PV module recycling in an environmentally efficient way. Certain aspects however had to be excluded from the Task 12 study due to the lack of available data, including the treatment of copper cables, the treatment of the backsheet and the recovery of copper and silver during these treatments. These processes still need to be added in a future life cycle assessment study.

Author: Bettina Sauer

This article is part of a monthly column by the IEA PVPS programme. It was contributed by IEA PVPS Task 12 – Enabling Framework for the Development of BIPV.

Casting doubt on green hydrogen’s utility is a popular sport. High capital costs and the vast spaces needed for associated renewables are cited as the main reasons preventing this clean energy source being commercially viable.

Hydrogen’s potential as a clean energy source has been widely discussed in recent years, driven by events such as the war in Ukraine. Hydrogen’s popularity stems from its ability to store and release energy without greenhouse gas emissions when extracted from water using renewable energy – or with carbon sequestration when the gas is produced using fossil fuels.

This has made hydrogen a critical component of energy planning as a “low to no”-CO₂ fuel source for hard-to-electrify segments of the transportation and heavy industry sectors.

The $2/kg mark is generally thought the sweet spot for hydrogen to become a commercially viable alternative fuel. Estimates suggest hydrogen could be produced at $2 at the factory gate by 2030 in countries with good renewables.

In Australia, we can quite easily reach the magical $2 mark – or less – by 2030, with growing demand in domestic and export markets. The federal government’s Hydrogen Headstart program, announced in May’s budget, showcases Australia’s commitment to the industry’s development. The strategy makes it clear Australia won’t be missing out on the benefits of hydrogen as it will stay on track with developments across other markets including the US, Canada, and Germany. Many Australian industrial organizations estimate the current cost of delivered hydrogen as well above $7/kg, however. Where is the cost differential coming from?

The key to successful hydrogen adoption is a systems approach to project development. Rather than viewing each component of the hydrogen production and delivery system in isolation, it is vital to consider the entire supply chain and to design the system as a whole. This holistic approach will minimize cost, while optimizing performance.

Three levers will dramatically reduce the cost of large-scale systems.

Optimize capital costs

Large-scale clean hydrogen production is still in its infancy, with many new projects announced but limited actual development. As a result, customers with large orders can have significant input into the design of hydrogen systems.

For example, customers seeking to build multi-gigawatt projects can engage directly with original equipment manufacturers (OEMs) to secure tailored technical specifications and get accurate prices.

These prices should consider future delivery timelines as the cost of renewables and electrolyzers are likely to significantly decrease in the coming years.

Balance-of-plant costs are often neglected but can take up a significant portion of the expense of renewables and electrolyzers. A deep dive into this component can reveal plenty of opportunity for cost reduction.

Match offtake needs

Companies should start with clarity about their hydrogen requirements and design systems accordingly. For example, an export project will need hydrogen (or a hydrogen carrier) ready to load on a ship upon arrival whereas an iron smelter needs a constant, reliable, daily supply. The various elements of the hydrogen delivery system should be put together with offtake requirement in mind.

As seen on many occasions in South Australia, having electrolyzer capacity on site can be useful when costs from the grid go negative, meaning businesses have the opportunity to turn their hydrogen production to generate a profit. This may make hydrogen production a smart addition to the overall system but a set-up wholly reliant on the grid is unlikely to cost-effectively meet the requirements for continuous, reliable hydrogen supply.

Whole-system approach

To ensure a constant, reliable supply of hydrogen, project proponents must focus on the entire supply chain to safeguard success. When designing large systems, it is tempting to break them up into different components and have people in the team (consultants, engineering firms, or OEMs) design them separately then put them back together. Instead of reducing costs, this approach will lead to higher expense.

Let’s say you need 1 GW of renewables input. The temptation is to design a renewables farm that delivers 1 GW of energy at all times but this is not necessary and is likely to result in high cost. The sun does not shine all the time so an engineer designing the renewable energy supply is likely to add storage (batteries or pumped hydro) or firming through the grid, adding substantially to the cost of electricity, and thus the cost of hydrogen.

Whole-system consideration of energy supply tells us running an electrolyzer at a lower capacity factor – with reduced energy costs – can optimize the price of hydrogen. There are multiple and frequent opportunities in the supply chain to firm output at a lower cost. It is important to understand how elements interact rather than focusing on maximizing utilization of any single component.

Sustainability

These three strategies could deliver hydrogen for less than $2/kg, based on experience working alongside organizations across the hydrogen supply chain and taking a systems approach to project development. This will be the key to our future energy security, as indicated by a joint Japanese and Australian consortium comprising governments, universities, and energy institutes.

While there are significant balance of trade opportunities for Australia when it comes to green hydrogen, it would be wise for local industry (with government support) to prioritize the domestic market and then use its learnings to move into export. Not only will this assist with our own decarbonization and create more jobs per kilo of hydrogen, it will also decrease the cost of hydrogen before moving into big export projects.

Exporting is inevitable, however. For example, Japan's interest in co-firing ammonia in coal plants creates hydrogen demand. Unlike Australia, where electrification is cheaper than using gas for households, Japan's high electricity prices will keep many households on gas.

As Australian industry reaches scale, and with the support of growing technical knowhow, prices will undoubtedly decline. It will be exciting to see hydrogen follow a similar cost-reduction trajectory as has been witnessed for solar and wind power.

About the author: Danny De Schutter is a partner at Sydney-based industrial cost reduction consultants Partners in Performance.

As an apartment dweller who wants to embrace solar energy, the gap in renewable energy access is ever-present. 

The cost of living, including electricity prices, is at its highest in decades. Self-generated solar energy has long been one of the easiest solutions for house owners to reduce their energy bills, access renewable energy, and increase resilience to blackouts. The proportion of households who have installed a solar system in the US has doubled since 2016, to 8%, according to a poll conducted by social-issue thinktank Pew Research Center in January last year.

But what do you do if you live in an apartment, like me? Even if you can get permission to install a solar system on an allocated area of your building’s roofspace, the cost is likely prohibitive. And if you are mainly out of the house during daylight hours, you would be lucky to offset more than 30% of your energy bills, according to Indian-owned solar manufacturer Renewable Energy Corporation. That makes the payback period much longer.

Opportunity

US body the National Association of Home Builders estimates 31.4% of Americans are in the same position as me and this represents a huge opportunity; local solar installers can broaden market outreach through multi-family projects, with portfolio rollouts offering replicable and scalable deal flow across states. What's more, addressing solar access for apartments will ensure that those most impacted by increasing energy costs are included in the clean energy transition; apartment residents earn, on average, 33% less than the median US household, according to the National Multifamily Housing Council.

There is an even bigger hurdle for apartment residents who are renting, as I do: landlords have little incentive to install solar on rented apartments since they typically bear the cost with the benefits passed on to tenants in the form of bill savings. That is why the adoption of residential solar has historically depended on home ownership.

Residential industry projections anticipate fourfold growth in home solar in the next decade and analyst Wood Mackenzie reports we have already seen a record-breaking 40% increase in solar adoption since 2021. The industry must address demand from the 43.9 million US residences in multifamily buildings, however, to maximize solar adoption.

Potential solution

Imagine solar energy from a single rooftop system could be shared between multiple apartments. The solar array collects energy and pipes it down the building to an inverter, which feeds into grid meters. These meters feed into each apartment and common area. Owners could then jointly invest in the system and multi-family landlords could provide solar energy to their tenants. 

Technology born in Australia and imported to the United States last year does just this. Allume Energy’s “SOLShare” product physically splits the energy from a single solar system, via a hardware device, and shares it between multiple meters. If the electricity is fed evenly into all meters at all times, as described above, significant amounts of energy will be fed back into the grid when apartments are not using electricity.

That’s where SOLShare’s “dynamic sharing algorithm” steps in. It feeds electricity to apartments that are using energy, thereby maximizing the energy consumed by the system and reducing the amount of energy fed back to the grid, making it an optimal system in states where there is no net metering. As a result, apartments can expect a 55% to 75% reduction in grid electricity consumption – more if they have a residential battery.

Over a month, SOLShare works out when and where to feed energy, in order to optimize energy consumption and ensure each apartment gets a fair share. Typically, the electricity will be evenly split but it can also be configured to provide more energy to common areas or larger apartments. Not all apartments need to participate and dwellings can be disconnected remotely at any stage.

Allume Energy already provides around 2,000 apartments with clean, affordable energy, with around half of those in social or affordable housing. Having launched recently in the US, Allume is currently operating in Florida and Mississippi and is pursuing projects in California, Georgia, Wisconsin, Illinois, and Texas. The company aims to have SOLShare available nationwide within the next 12 months.

Allume Energy works with multi-family apartment-owning landlords directly and via its growing network of certified SOLShare solar installers.

Owner-occupiers can engage directly with a certified SOLShare installer, who will arrange a site visit and provide a quote for the building as they would for a solar system on a house. The system can then be installed within two months to four months, with little disruption to residents and no change to their current utility setup – except lower bills. Apartment residents can also inquire through the Allume website, enabling the company to connect them with an installer partner. 

Multi-family apartment block landlords can purchase a solar system, priced per unit, directly from Allume. The company works with installer partners to deliver a turnkey solution and landlords can allocate more energy to common areas or larger apartments to suit their needs. There is a small, ongoing connection fee per unit for monitoring a building’s solar usage. 

Landlords can use solar as a revenue stream by pocketing some or all of the savings from the solar system. Alternatively, they can pass the savings on to tenants, improving rentability and occupancy rates. Inquiring about solar access with an asset management firm would be one place to start. 

What's the bill?

Available incentives include a 30% investment tax credit, a low-to-moderate income adder worth up to a further 20% tax credit, and a further 10% energy communities adder. Allume also works with clean finance providers to offer affordable options with no upfront costs. The Allume team can guide customers through incentive and finance options in their area and tailored to their circumstances.

By expanding solar access, we can improve the quality of life for vulnerable parts of the community, promote environmental sustainability, and create economic opportunity. Low to moderate income solar energy access for apartment owners and renters is crucial to achieving energy equity and addressing the burden of rising utility bills.

Many apartment owners and renters across the US can now access solar energy directly from their rooftops and those who can’t will be able to in the next year, as more utilities come on board. Government incentives, combined with green finance options, are helping improve affordability so that the people who would most benefit from energy bill savings can access it.

Nevertheless, policymakers, utilities, and community organizations must continue to collaborate to implement supportive policy and programs.

About the author: Mel Bergsneider is executive account manager at Allume Energy, responsible for business development in the US market. As the first US-based employee at Allume, Mel leads the Australian startup’s expansion across target markets including California, New York, and Florida. Mel works closely with affordable housing providers, solar installers, and real estate developers to provide solar energy benefits to tenants.

As Europe moves towards its decarbonization targets with sales of internal combustion engine cars to be banned at various points between 2030 and 2035, and alternative fuels no longer merely optional, gas station owners are pausing to reimagine the future of the forecourt.

Alongside changing driving habits, our collective approach to driving is changing too. Service stations across the EU will likely be revamped to provide drivers with a whole new, consumer-friendly experience.

This raises several questions.

Will city centers stop selling petrol and diesel entirely? Might subscription-model pricing mean drivers stay loyal to their preferred forecourt? How will retail options change with the increased “dwell time” of EV charging?

As local governments invest in EV infrastructure and other clean fueling options, it is clear that the traditional, “stop-and-go” service stations could transform into multi-purpose destinations replete with new-look retail and leisure options.

Consumer experience

It’s forecast that European EV infrastructure boasts the most mainstream motoring potential of all clean fueling options, with 1.39 million units sold across the continent per year. This is sure to increase dwell times across forecourts as even the most rapid public EV chargers take 10 minutes to refuel a vehicle.

Forecourt station owners can capitalise on this uptake in dwell time by enhancing their retail and entertainment offering. Convenience stores will likely be transformed into multi-purpose hubs with fresh food and a fast, easy, and digitally enabled shopping experience. This could include easy payment through apps, cashless stores, and whole-basket scanning.

Whereas convenience drove previous generations of fuel buyers, it’s likely that sustainability concerns will underpin the purchasing habits of the future. It is likely stations will have to carefully curate their product offering and building out shops and cafes could offer further opportunities to improve profit margins. Some 66% of prospective EV drivers, for instance, report they would frequent retailers more regularly if they provided usable charging facilities.

Additional services will also likely take center stage, including children’s play areas, click-and-collect departments and co-working spaces.

Pump modernization

As stated, the forecourt is likely to include a mix of EV charging and other alternative fuels, which will require additional space.

One of the biggest threats to the fueling industry at the moment is petrol pump skimming, with consumers increasingly falling prey to opportunistic thieves who install devices at the pump which can retrieve payment card details. Enhanced security software at the pump can protect against this.

Other areas of pump modernization will likely also be technologically-led. This could include a consumer-friendly interface with EU languages; the ability to pay by card, app, or in-car; and digital pricing transparency.

Drivers may also soon be able to order refreshments and other items at the pump before collecting in-store. This is, currently, an emerging trend in the North American market and will likely soon hit Europe, the Middle East, and Africa.

Traditional pumps

The year 2030 will not signify the complete demise of traditional vehicles. Petrol and diesel pumps will still be required long after the switch and will still have demand in the marketplace.

The average lifespan of an European car is 12 years, which will mean that traditional pumps are needed beyond 2040. As internal combustion engine cars become less mainstream, it is likely that these pumps will be set apart from cleaner refueling, especially with an expected emphasis on sustainability across all areas of the forecourt, not just in terms of charging and refueling but in the retail and leisure offering too.

Future of Fuel

While, for the foreseeable future, traditional petrol and diesel pumps are likely to remain fixtures of the forecourt, it is expected that the petrol station as we know it will become a completely evolved consumer experience.

Station owners can take full advantage by offering bespoke food, beverage, and entertainment options while forecourt and pump modernization, and recharging subscription services, will surely become commonplace.

The rise of the alternative fueling forecourt offers massive opportunities for fuel retailers and businesses should look to double down by offering access to the plug – and the pump.

About the author: Lise-Lotte Nordholm is VP and general manager of clean energy and global platforms at fueling company Dover Fueling Solutions.

EV sales passed 10 million last year and the International Energy Agency predicts 40 million in 2030. Growth is underpinned by battery manufacturers striving to keep pace with demands for enhanced performance and range. Such growth is driving a pressing waste challenge.

After 10 years to 15 years, EV batteries retain 70% to 80% of their original capacity, rendering them unsuitable for further automotive use, according to Dutch EV equipment supplier EVBox. The International Council on Clean Transportation estimates, by 2040, some 14 million EV battery packs will reach end-of-life annually. There is an urgent need for safe, responsible end-of-life battery management.

Research has focused on recycling batteries, to recover valuable materials including cobalt and lithium, with 35 EU recycling projects active or due by 2025. Less attention has been paid to preserving the inherent value of batteries. The concept of giving devices a second, or even third life, is gaining traction as it maximizes utilization of materials and energy and postpones recycling for years, or even decades.

Recirculate is a project funded by the EU’s Horizon Europe research program and Swiss federal body the State Secretariat for Education, Research and Innovation. The initiative is pioneering a “4R” approach for batteries, encouraging repair, reuse, and remanufacture, before recycling. It will revolutionize the battery sector by developing the technologies and systems to enable cascading reuse of batteries in second-life applications such as battery energy storage systems. Led by Finland’s Centria University of Applied Sciences, Recirculate brings together research and industrial partners from eight countries, including the Ford Otomotive Sanayi carmaker owned by Ford and Turkish conglomerate Koç Holding, and DHL.

Barriers to reuse

The first major hurdle to giving batteries a second-life is understanding their type and condition. EV battery packs comprise thousands of cells organized into modules and do not feature standard labelling. For optimal performance, second-life batteries must use cells with matching electrode chemistry and condition, creating a need for data on battery cell type and parameters such as state of charge, remaining useful life, state of health, and state of safety – collectively known as “state of x” (SoX). Battery management systems hold some of this data at pack level but original equipment manufacturers do not typically provide this information. Obtaining cell-level SoX data requires time-consuming, costly, unreliable analytical methods. Recirculate is developing diagnostic tools and processes to accelerate characterization of battery SoX at pack, module, cell, and other levels.

A lack of safe, rapid, scalable battery pack dismantling – to enable module and cell reuse – is another barrier. There are hundreds of battery designs with variations in size, electrode chemistry, and form factors. The need to plan for every possible pack, module, and cell permutation makes robotic disassembly impractical. Robotic systems also struggle with damaged or non-conforming batteries. Manual dismantling is the norm but is slow, expensive, and dangerous; fully discharging a battery causes irreversible damage, preventing further use, so operators work on live batteries, exposing them to potential electrical, fire, and chemical hazards. Recirculate aims to revolutionize battery dismantling with artificial intelligence-based control systems to adapt to different battery designs and conditions, providing a faster, safer, and more cost-effective alternative to manual disassembly.

The storage and transportation of used batteries also poses challenges, due to the risk of thermal runaway and fire. Europe classes EV batteries as dangerous goods, in part due to their susceptibility to thermal runaway when subjected to impact or damage. Complying with regulations on storage and transport creates a safety and cost barrier to transporting used batteries across the EU, impeding second-life adoption. Recirculate is developing a cost-effective, intelligent, safe transport and storage system for battery packs, modules, and cells. Integrating temperature sensors and fire suppression into battery travel cases, the system will enable early detection of thermal runaway risk and the development of effective fire mitigation and prevention strategies.

Supply chain

Although the technical challenges above are significant, the biggest barrier to the adoption of used batteries is the fragmented state of the second-life battery supply chain. Manufacturers must build and maintain business-to-business supplier relationships, which restricts supply of used products and impedes the sourcing of battery modules and cells of the same SoX for reuse.

Ideally, second-life battery manufacturers should be able to source used-battery components on the open market. However, a lack of transparent and trustworthy data on the type and condition of devices inhibits trade, increasing costs for battery remanufacturers as they must rigorously assess and characterize all modules and cells before deciding how to use them.

Recirculate will address this issue by developing, blockchain-backed product passports, holding a tamper-proof record of information on batteries and their components. This will provide supply chain actors with the trusted information they need to make informed decisions on how best to source and process used batteries. The program will establish a third-party marketplace underpinned by blockchain product passports, empowering consumers and commercial actors to source batteries of a specific type and condition with confidence.

A new model

The EU-Swiss initiative envisions an independent marketplace to create new business opportunities throughout the battery value chain. By expanding the supply of second-life batteries and their components and supplying a platform for services related to battery characterization, storage, transport, dismantling, remanufacturing, and trading, Recirculate aims to reshape the industry according to the needs of industry, consumers, and the market.

Recirculate consortium members will engage across the battery value chain to understand the challenges they face. This collaboration will ensure the project's competitive solutions align with the requirements of all interested parties, positioning European industry at the centre of a more sustainable battery value chain.

The Recirculate program will be delivered by Centria and compatriot automation and robotics company Probot Oy; Norwegian battery management business Eco Stor AS; Berlin-based supply chain traceability specialist Minespider Germany GmbH; Swiss battery-as-a-service provider Libattion GmbH and compatriot not-for-profit research entity the Centre Suisse D'electronique Et De Microtechnique Sa; Turkey-based DHL Lojistik Hizmetleri AS; Ford Otomotiv Sanayi; Ireland’s Iconiq Innovation Ltd; Spanish research and technology outfit Fundacio Eurecat; and Sweden’s Dafo Vehicle Fire Protection AB.

About the author: Dr Stephen Rippington is science communicator and innovation management consultant for Iconiq Innovation, supporting companies to develop circular and sustainable solutions. He has secured grant funding for EU and UK research and development projects across a range of sectors and has more than 20 years’ experience of planning and delivering complex, multi-disciplinary applied research projects for academia and industry.