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

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

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

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

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

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

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

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

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

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

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

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

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

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

Battolyser Systems has developed an energy system to store and supply electricity as a battery and produce hydrogen via electrolysis. It is an optimization of the nickel-iron battery patented by Thomas Edison at the turn of the 20th century. 

The company, which recently started production of its patented dual battery-electrolysis system in the Rotterdam area, currently produces systems up to a couple of megawatts. It aims to manufacture 50 MW systems in its production facility by 2024, and 200 MW by 2025. 

“The technology is based on nickel-iron electrodes. They are combined with alkaline electrolysis technologies that are commercially available today, with a proven track record of 20 to 30 years lifetime,” said Geert Wassens, fundraising associate at Battolyser Systems. “Integration of these technologies remarkably improves performance, lowers cost and increases uptime.”

The electrodes are in a conductive electrolyte circulated through the cells. In the first electrochemical reaction, the electrodes are charged and store electrons, acting as a battery. When one keeps charging (overcharge), hydrogen and oxygen are formed in a subsequent reaction. Gaseous hydrogen is produced at the negative electrode (cathode) and oxygen at the positive electrode (anode).

The company said the system could hit a lower LCOH of around €1.50/kg in the most appropriate locations by 2025. 

“In the most favorable geographies, the Battolyser is able to offer ~€2/kg by 2025. An important note to this analysis is that it does not yet include the positive economic impacts of discharging electricity from the Battolyser to the grid, it only considers revenue from producing hydrogen,” Wassens told pv magazine. “Therefore, the advantage in LCOH of Battolyser over competing alternatives will be even greater. Including this value, the LCOH is near to €1.50/kg.”

Battolyser Systems said the battery function can monetize daily power imbalances, while the hydrogen can monetize seasonal power imbalances and provide feedstock to industries that cannot be electrified. It said it can reach up to 85% system efficiency and up to 90% at stack level.

Battolyser Systems has signed a deal to develop a second production facility in the Rotterdam area. In 2026, the production facility, co-owned by the Rotterdam port authority, will be commissioned to add 1 GW of production capacity.

Battolyser Systems and the European Investment Bank (EIB) have also signed a €40 million financing agreement in Rotterdam during World Hydrogen Week.

“The financing will enable the company to scale its production facility in Rotterdam towards mass production of its combined electricity storage and electrolyzer stack system,” said Battolyser Systems.

The company said it does not use any critical raw materials, resorting only to nickel and iron, in line with the recent normative and political developments at the European level, including the RED II and the Critical Raw Materials Act. 

“We have a number of hydrogen projects in the pipeline that we are looking to sign in the near future, although perhaps not necessarily still this year,” an EIB spokesperson told pv magazine. 

Four-plus-hour energy storage accounts for less than 10% of the cumulative 9 GW of energy storage deployed in the United States in the 2010-22 period. However, this type of technology is likely to assume a more important and versatile role on the grid in the years to come, according to NREL's new publication.

NREL’s earlier studies identified economic opportunities for hundreds of gigawatts of six to 10-hour storage even without new policies targeted at reducing carbon emissions.

“Longer-duration energy storage may lead to better grid resilience,” said Paul Denholm, NREL model engineering senior research fellow and lead author. “There's an upside to developing and deploying greater storage, whether that value is in the ability to store more renewable energy or meeting winter energy demand.”

Historically, four-hour storage has been well-suited to providing capacity during summer peaks, and its ability to serve summer peaks is enhanced with greater deployments of solar energy.

As a result, several wholesale market regions have adopted a fixed “four-hour capacity rule” that fully compensates storage with at least four hours of duration and has no additional capacity revenues for longer durations. That means that a six-hour battery does not receive any more revenue than a four-hour one.

“This rule, along with limited additional energy arbitrage value for longer durations and the cost structure of Li-ion batteries, has created a disincentive for durations beyond 4 hours. Based in part on this rule, in 2021 and 2022, about 40% of storage capacity installed was exactly 4 hours of duration, and less than 6% had durations of greater than 4 hours,” NREL writes in its new publication.

However, the addition of solar, extreme weather conditions and building heating electrification are changing the equation and peak demand is becoming more significant in the winter than in the summer, as already seen in the Southeast and Texas.

“Energy storage could help meet increasing winter demand,” Denholm said. “Increased storage can also support transmission and resilience, further increasing the value of developing energy storage with more than four hours of capacity.”

Various technologies – such as thermal storage or next-generation compressed-air energy storage – have the potential to reach cost parity with lithium-ion batteries and longer service lifetimes. However, the new technologies must compete with the established lithium-ion, which had a decades-long head-start, and will require deployment at scale.

“We have promising technologies that, with development, can meet winter demand peaks and compete with lithium-ion technology,” Denholm said. “Reliability of the grid is the goal – greater storage can help us get there.”

From pv magazine Italy

The submarine cable will connect a new converter station in Galatina, southern Italy, with a station in Thesprotia, in Greece's Epirus region

“Terna, with the support of the Puglia Region and other regional administrations, has started the voluntary consultation process as early as 2022,” said Terna.

Electrification of transport entails an inevitable increase in electricity demand, and perhaps more critically, peak power needs. While the number of electric cars on the streets has been rapidly growing in recent years, for aviation, short-haul flights are first in line for fuel exchange to electrified transportation given the limited energy density of batteries presently on offer.

In a new paper, researchers from the RISE Research Institutes of Sweden, Chalmers University of Technology and Uppsala University have quantified rising demand for airport energy from electric aviation and vehicles focusing on the airport in Visby, Sweden. They analyzed the potential techno-economical gains from installing solar and battery storage on site.

Their results show that substituting the short-haul flights with electric aviation increases the annual load demand by 89.4% and the annual peak power demand by 1 MW.

With PV alone, the grid demand reduces by 871 MWh through self-consumption (80%), the researchers found. They also observed, however, that peak reduction is modest and a consequence of the coincidence of PV output from 2.3 MW of arrays installed on-site and peak power demand.

Battery energy storage systems (BESS) further reduce grid demand, up to 18.3% compared to reference scenario with PV alone. The researchers also modeled BESS charge and discharge control in four ways, including a novel multi-objective (MO) dispatch to combine self-consumption enhancement and peak power shaving. They compared each model scenario for peak power shaving ability, self-consumption rate and pay-back period, as well as evaluated the BESS controls for annual degradation and associated cost.

They found that relative to the “PV alone” reference scenario, the newly proposed dispatch operation enhances self-consumption by 8.6% and “sufficiently shaves the power peaks.”

The MO dispatch operation also shows the lowest payback period of 6.9 years among the analyzed battery scenarios. It also reduces the battery’s idle period, resulting in an annual degradation (3.7%/a), which is in the same order of magnitude as the other dispatch algorithms (3.5–4.2%/a), the Swedish researchers reported.

The researchers discussed their findings in “Evaluating the role of solar photovoltaic and battery storage in supporting electric aviation and vehicle infrastructure at Visby Airport,” which was recently published in Applied Energy.

SWBs are a promising type of sodium-based battery technology which uses seawater as the cathode. One of their advantages is the ability to store energy over short and long timeframes and provide even annual storage.

In a recently released paper, researchers from the University of Perugia and the Sapienza University of Rome have explored the potential of SWBs focusing on renewables-rich Sardinia Island as a case study. The SWB technology they considered employed sodium-biphenyl (Na-BP) as the anolyte. It resembles a conventional redox flow battery with both the anolyte and the catholyte (seawater) flowing through the battery cells.

According to the researchers, a key strength of Na-BP-based SWBs lies in the possibility to externally store metallic sodium. This allows for an extension of the storage timeframe by increasing the Na metal external reservoir, enabling hourly to monthly and seasonal energy storage with only one device and thus decreasing the investment costs.

“This work aims at demonstrating the applicability of SWB to meet the European energy requirements, to arise the interest of the public and private sectors into the further development needed to bring the laboratory scale cells so far developed into commercial applications,” said the researchers.

To this aim, the researchers have investigated SWBs for short-term application when coupled with wave energy converters and found that this could allow for a potential reduction of more than 85% of generated power fluctuations on the Sardinian grid. In this case, the power ramp up reduction was calculated as the difference between two consecutive power values with a timestep of one second and the energy was stored in the Na-BP anolyte.

In the long-term scenario, the researchers found that SWBs could allow for coverage of Sardinia’s seasonal and even annual energy demand thanks to high volumetric densities of Na metal, which is around four times that of compressed hydrogen at 700 bar. The full decarbonization of the Sardinian grid involves integration of approximately 340,000 m3 of Na metal, corresponding to a 12-meter-high Na reservoir covering a surface of less than four soccer fields, the researchers calculated.

They also found that SWB application could eventually meet around 29% of the desalinated water requirements of the Sardinian population, in addition to harnessing its carbon-dioxide capture auxiliary functionality, which results in 37.3 grams of CO2 per stored kWh.

“The results of the modeling demonstrate the effectiveness of SWB-based energy storage combined with the abundant renewable sources of Sardinia, enabling the full decarbonization of the energy system on the island,” the researchers write. “Moreover, SWBs desalination and CO₂ capture functionalities is an exemplar of clean energy transition implementation that can be extended to other islands and coastal areas.”

They discussed their findings in “Na-seawater battery technology integration with renewable energies: The case study of Sardinia Island,” which was recently published in Renewable and Sustainable Energy Reviews.

Scientists from India and South Africa have assessed the technical and economic opportunity of operating hybrid PV-biogas microgrids to charge electric vehicles (EVs).

“The study carried out could be useful for the authorities working in EV charging stations infrastructure development, policymakers and researchers,” the research group said. “The challenges associated with this work are mass adoption of EVs and consumer’s readiness to purchase the technology.”

They introduced the system in “Assessment of microgrid integrated biogas–photovoltaic powered Electric Vehicle Charging Station (EVCS) for sustainable future,” which was recently published in Energy Reports. The study was conducted by scientists from India’s REVA University, SDM College of Engineering and Technology, RYM Engineering College and the National Institute of Technology, along with a scientist from South Africa’s University of Johannesburg. The results were first shown at the 8th International Conference on Sustainable and Renewable Energy Engineering.

A German-Swiss research team introduced a novel optimization method for the integration of heat pumps in non-continuous industrial processes.

The novel technique utilizes Pinch Analysis, which identifies the optimal temperature levels for heat exchange within a system, and provides the coordinates for the optimal design and sizing of the heat pumps.

“In Pinch Analysis, most approaches to design the heat recovery system as well as the utility system are based on a single operating point or a couple of operating points. In the past, this was due to the lack of temporally detailed process data,” the researchers explained. “However, the available process data is expected to increase drastically by the use of transient process simulation models.”

The researchers used software simulation to obtain detailed process data and utilized 8,759 time slices over one year, calculating an optimal set of heat pump parameters by mathematical optimization. For their case study, they chose an automotive paint shop, where variations in heating and cooling demands primarily arise from weather conditions.

The novel methodology considers different economic optimization objectives and is intended to minimize Opex over the whole year and maximize the net present value (NPV) of the heat pump investment. It also aims to maximize the internal rate of return (IRR) of the heat pump investment.

The scientists compared the performance of a system designed with the novel approach with that of a system conceived with the time average (TAM) model, as well as with that of a system based on an optimization method that considers the entire annual process data as well as NPV and IRR.

.“The TAM averages the heat loads over the batch period and allows for basic targeting,” the academics explained, noting that this configuration achieved a coefficient of performance (COP) of 2.56. “The integration of the TAM heat pump can already provide Opex savings of 1.75% but has very high Capex due to its large heating capacity. With an IRR of 18.4% and an NPV of €167,183 ($175,433), it is already a very worthwhile investment.”

The system designed with the novel technique, by contrast, achieved Opex savings of 3.94%, an IRR of 56.3% and an NPV of €610,15. Its COP was 2.41. When optimized to NPV, the novel method showed Opex savings of 3.93%, an IRR of 60%, an NPV of €615,989 and a COP of 2.48. Finally, when optimized for IRR, the OPEX savings were 2.93%, the IRR was 70.5%, the NPV was €476,556 and the COP was 3.17.

The scientists claim that, by utilizing the new methodology, a 33% smaller heat pump could be integrated. “The smaller size and greater savings show particularly in the evaluation of the profitability of the investments,” they concluded.

They presented their findings in the study “Heat pump integration in non-continuous industrial processes by Dynamic Pinch Analysis Targeting,” published in Applied Energy. The research group was formed by scientists from the German Aerospace Center and the Lucerne University of Applied Sciences and Arts.

Scientists from the University of Zaragoza and renewable energy developer Atalaya Generación have introduced a novel optimization method for the management of pumped hydro storage integrated with grid-connected PV and wind power plants.

They said they tested the model with real data, satisfying electricity demand and maximum profit.

“The goal of this study is to develop an hourly mathematical model that allows for the optimal management of grid-connected renewable generation facilities and pumped hydro-energy storage with reversible pump turbine,” the scientists emphasized. “The model can take advantage of opportunities in the electricity market through the purchase and sale of excess energy generated to the grid.”

In the paper “Optimal scheduling and management of pumped hydro storage integrated with grid-connected renewable power plants,” published in the Journal of Energy Storage, the research group explained that the model is based on a mixed-integer optimization problem, which is a type of mathematical problem often used in energy scheduling.

“The model incorporates the purchase of energy through a contract indexed to electricity prices in the wholesale market,” the academics explained. “This assumption allows us to obtain an optimal economic dispatch for every hour. In addition, the model includes the possibility of selling surplus production at a price set in the electricity market every hour.”

The model assumes that evaporation losses do not affect the performance of the system, and that wind and solar power prioritize meeting the electricity demand required by the system each hour.

The researchers have used 2019 generation data from existing plants in Spain’s Ebro Valley. These plants are represented by 860 MW of PV facilities, 456 MW of wind farms and a pumped hydro storage facility with a storage capacity of 5,750 MWh.  The wind farms are estimated to generate 1,352 GWh per year and the photovoltaic plants 2,065 GWh.

In order to analyze the techno-economic performance of the system, the scientists took as a benchmark the hourly prices of the Spanish wholesale electricity market set by the market operator OMIE in 2019. They compared the performance of the pumped hydro-wind-solar complex to that of a reference system without pumped hydro storage and found that the former reduces the cost of purchasing energy in the electricity market by up to 27 %.

“Compared to the case without storage, the integration of pumped hydro-energy storage reduces the amount of energy to be purchased from the electricity market to satisfy the demand by 20%, which implies an economic saving in the operation of the system of up to 27%,” they explained.

In addition, the scientists found that the system including the pumped hydro storage facility may help avoid energy curtailment.

“The application of the proposed model for the optimal operation of electrical systems based on renewable generation combined with large-scale pumped hydro storage helps improve the competitiveness and viability of power systems,” the researchers concluded. “The best decision is made every hour to reduce high energy costs and obtain efficient and resilient management of water use.”

“The research emphasizes achieving significant energy savings and improving indoor comfort through the integration of photovoltaic systems and bio-based materials,” researcher Sara El Hassani told pv magazine. “We used a combination of passive and active strategies – passive approaches include the use of local eco-materials for insulation, while active approaches involve the introduction of renewable energy techniques.”

Overall, the bio-based walls reduced simulated peak heating loads by around 24.3%, and decreased cooling loads by about 26.7%.

“All of these findings support the use of plant fibers as a sustainable practice in developing local and efficient adobes for improving passive heating and cooling in rural arid and semi-arid regions,” the scientists said.

Their study, “Towards rural net-zero energy buildings through integration of photovoltaic systems within bio-based earth houses: Case study in Eastern Morocco,” was recently published at Solar Energy. The research group includes scientists from Mohammed 1st University and the Green Energy Park. They said they will try to develop a standalone PV system within a bio-based building prototype in the future.

From pv magazine USA

The days of the solar industry operating as a “net metering type of industry” are “starting to be numbered,” said Jigar Shah, the director of the US Department of Energy’s Loan Programs Office, at the recent RE+ 2023 conference in Las Vegas.

“Most solar systems come with batteries, and most are integrating smart panels,” he said. “They’re integrating demand response and load control capabilities into the inverter controls.”

Because a solar-plus-storage system with those features can earn its owner compensation through participation in a virtual power plant (VPP) – an aggregation of similar systems often managed by a third-party aggregator – Shah encouraged the solar industry to see its future in VPPs. The deployment of VPPs to date is shown in the featured image above.

Besides distributed storage, other distributed energy resources that can be aggregated into a VPP include electric vehicle chargers, smart thermostats, and smart electric water heaters.

Shah said that electric utilities are “looking to bury the hatchet and really deploy a lot of these technologies at scale” through VPPs. “Frankly, it is the only way for them to integrate all of the huge load that is coming their way.”

Shah said utilities Duke Energy, serving the Carolinas, and Luma Energy in Puerto Rico have announced large VPP projects, the latter with the residential solar firm Sunnova.

Addressing the solar industry professionals in his audience at RE+, Shah said “you’re the ones who should be integrating all of the technologies that are shown on the floor out there, into a coherent package.”

For its part, the DoE anticipates lending support on the order of $100 million to advance VPPs, Shah said. Sunnova’s inclusion of low- and moderate-income Puerto Ricans in its VPP project is being supported by $3 million in loan support, while other applicants are already preparing $30 million in loan requests.

To continue reading, please visit our pv magazine USA website.

Solar photovoltaic, thermoelectric energy production and wind energy production

In the week of September 18, solar energy production decreased in almost all analyzed markets compared to the previous week. The German market registered the largest decrease of 22%. Other markets where solar energy production decreased included France, down 2.0%, and Italy, down 18%. The exception to this trend was the Iberian Peninsula, where production increased by 12% week‑on‑week. In addition, on Sunday, September 24, the Spanish market reached the highest solar thermoelectric energy production since the beginning of September with 22 GWh, and on Wednesday, September 20, the second highest photovoltaic energy production in the same period with 126 GWh. The Portuguese market also generated 13.8 GWh of photovoltaic energy on September 23, the highest value since the end of August.

For the week of September 25, according to AleaSoft Energy Forecasting’s solar energy production forecasts, an increase is expected in all analyzed markets.

As for wind energy production, in the week of September 18, a week‑on‑week increase was registered in most of the markets analyzed at AleaSoft Energy Forecasting. The largest increase, 295%, was registered in the Italian market, followed by 210% in the German market. The smallest increase, 28%, was registered in the Spanish market. The exception was the Portuguese market with a fall in wind energy production of 38%.

In the third week of September, daily wind energy production reached levels not seen since spring or summer in several markets. In Spain, for example, 290 GWh was generated on September 21, the highest value since May of this year. In the German market, 653 GWh was generated on September 19, the highest wind energy production in this market since the second week of August. One day later, on September 20, 191 GWh was generated in the French market, a level not reached since August 6.

For the week of September 25, AleaSoft Energy Forecasting’s wind energy production forecasts indicate that it will decrease in all analyzed markets.

Electricity demand

In the week of September 18, electricity demand decreased in all analyzed markets compared to the previous week. The largest decrease of 9.2% was registered in the Dutch market, followed by the Spanish market with a decrease of 5.1%. The smallest decrease was registered in Germany, with a decline of 0.3%. In the other analyzed markets, the decline in demand ranged from 1.8% in Belgium to 4.2% in Portugal.

During the same period, average temperatures decreased in all analyzed markets compared to the previous week. The smallest decrease was registered in Italy with 0.3 ºC. In the rest of the analyzed markets, average temperatures decreased from 1.5 ºC in Portugal to 3.4 ºC in France.

According to AleaSoft Energy Forecasting’s demand forecasts, for the week of September 25, electricity demand is expected to continue to decline in most of the European markets analyzed, with the exception of France and the Iberian Peninsula.

European electricity markets

In the week of September 18, prices in all European electricity markets analyzed at AleaSoft Energy Forecasting fell compared to the previous week. The largest drop, 87%, was reached in the Nord Pool market of the Nordic countries, while the smallest decline, 1.5%, was registered in the MIBEL market of Portugal. Elsewhere, prices fell between 4.2% of the Spanish market and 31% of the EPEX SPOT market of Germany, Belgium and the Netherlands.

In the third week of September, weekly averages were below €100/MWh in almost all European electricity markets. The exceptions were the Portuguese market and the IPEX market of Italy, which reached €102.26/MWh and €118.27/MWh, respectively. On the other hand, the Nordic market had the lowest average price at €2.62/MWh. In the rest of the markets analyzed, prices ranged from €68.42/MWh in the French market to €99.43/MWh in the Spanish market.

Negative hourly prices were registered on September 19, 20 and 24 in the German, Belgian, French and Dutch markets. In the Nordic market, in addition to these days, negative hourly prices were reached on September 21, 25 and 26. Likewise, on the 19^th, the Nord Pool market price was below zero, averaging ‑€0.60/MWh. In the case of the British market, negative hourly prices were registered on September 19, 20 and 25. The lowest hourly price of ‑€5.74/MWh was reached in the German market on September 19, from 14:00 to 15:00. This price was the lowest since the first half of August in this market.

On the other hand, in the Spanish market, on Sunday, September 24, from 12:00 to 16:00, the price was €0/MWh. In the Italian market, that day, from 13:00 to 15:00, a price of €10.00/MWh was registered, the lowest since May.

During the week of September 18, despite the increase in the average price of gas and CO₂ emission rights, the general decline in electricity demand and the significant increase in wind energy production in most of the analyzed markets led to the fall in European electricity market prices.

AleaSoft Energy Forecasting’s price forecasts indicate that in the fourth week of September European electricity market prices might increase, influenced by the decrease in wind energy production, as well as by increases in demand in some markets.

Brent, fuels and CO₂

In the third week of September, settlement prices of Brent oil futures for the Front‑Month in the ICE market remained above $93/bbl. The weekly minimum settlement price, $93.27/bbl, was registered on Friday, September 22 and it was 0.7% lower than the previous Friday. On the other hand, the weekly maximum settlement price, $94.43/bbl, was reached on Monday, September 18. This price was 4.2% higher than the previous Monday and the highest since the first half of November 2022.

In the third week of September, production cuts in Saudi Arabia and Russia led Brent oil futures settlement prices to reach values above $93/bbl. However, concerns about the evolution of the economy and expectations of high-interest rates for a longer period of time exerted their downward influence on prices, contributing to their decline during the week.

As for TTF gas futures in the ICE market for the Front‑Month, on Monday, September 18, they registered a settlement price of €34.47/MWh, 3.8% lower than the previous Monday. But, starting on Tuesday, September 19, prices began to increase. This growing trend continued on Monday, September 25, when a settlement price of €44.44/MWh was reached. This price was 29% higher than that of Monday, September 18, and the highest since the beginning of April.

In the third week of September, the proximity of the coldest months led to an increase in TTF gas futures prices, despite the high levels of European reserves. The alterations in the gas flow from Norway, which will be extended to the month of October, also exerted an upward influence on prices. Meanwhile, the labor conflict at Australian liquefied natural gas export plants continues.

The weekly minimum settlement price for CO₂ emission rights futures in the EEX market, for the reference contract of December 2023, on Monday, September 18, was registered at €80.84/t. This price was 1.0% lower than the previous Monday and the lowest since early June. However, during the rest of the sessions of the third week of September, prices increased. As a consequence, the weekly maximum settlement price of €85.48/t was reached on Friday, September 22 and it was 3.9% higher than the previous Friday.

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

The next webinar in the monthly webinar series of AleaSoft Energy Forecasting and AleaGreen will be held on Thursday, October 19. Speakers from Deloitte will participate in the webinar for the fourth time. In addition to the prospects for European energy markets for the winter of 2023‑2024, the financing of renewable energy projects and the importance of forecasting in audits and portfolio valuation will be analyzed.

Scientists from Sweden's Chalmers University of Technology sought to define optimal capacity expansion planning for off-grid PV mini-grids in rural Ethiopia and found that there may be serious issues in achieving cost-effectiveness and reliability at the same time.

“A significant number of the mini-grids deployed in off-grid areas of developing countries are experiencing serious reliability issues,” the academic explained in the paper “Long-term optimal capacity expansion planning for an operating off-grid PV mini-grid in rural Africa under different demand evolution scenarios,” which was recently published in Energy for Sustainable Development.

“At the root of the capacity shortage problem lies inaccurate initial demand assessments, and subsequent under-sizing of the mini-grids. Many mini-grids are designed using static and artificial load profiles, assuming that the present consumption levels of customers reflect their future energy needs.”

The researchers investigated the case study of a mini-grid operating in a small town called Omorate, located in southern Ethiopia. Costumers of this mini-grid in 2022 had a demand of 638.8 MWh, of which 250 MWh, or 40%, was unmet.

This system has a capacity of 375 kW and consists of a PV system, converters, maximum power point trackers (MPPTs), a storage system using five LiFePO4 battery packs with a total nominal storage capacity of 600 kWh, a diesel generator with 100 kW power, a distribution board and loads.

Using the HOMER Pro optimization software, they assumed three expansion scenarios for the mini-grid. In all scenarios, a maximum of 10% yearly shortage was allowed.

In the first scenario, the system expansion was conceived to meet the current demands – estimated to be on average 1750 kWh/day and 639 MWh/year. The second scenario assumed a 5 % annual demand growth rate, resulting in a daily and annual demand of 3,039 kWh and 1,109 MWh, respectively. The third scenario assumed a 15% annual demand growth rate for business and productive users only, summing up to daily and annual demand of 4,075 kWh and 1,487 MWh, respectively.

Through their analysis, the scientists found the third scenario had the lowest levelized cost of electricity (LCOE), of $0.404/kWh. The first scenario resulted in an LCOE of $0.887/kWh, and the second was $0.592/kWh. However, the average electricity price currently paid by households in the area was $0.030/kWh, meaning that the revenues generated from power sales may not be able to recover the cost of the expansion.

“The findings highlight two important points,” the paper says. “First, the financial viability of mini-grid capacity expansion heavily depends on the electricity prices. Second, ensuring the financial viability of off-grid mini-grids in Ethiopia requires designing the systems to support productive use of electricity and introducing appropriate incentive mechanisms and tariff restructuring.”

The researchers explained in the paper that the 15% expanding scenario will be the most expensive to complete, with a total cost of $7.4 million. The 5% expansion will cost $5.9 million, and the meet-the-demand scenario will cost $4.2 million.

Their findings also show that in all scenarios, the battery expansion accounts for most of the total capacity expansion costs, accounting for 52%, 62% and 73%, respectively.

“It is always recommended to use larger capacity batteries to meet a given electrical load. However, a larger battery also increases system costs, the researchers said. “Conversely, expanding the mini-grid solely based on cost minimization may not produce the desired reliability. This highlights the significant non-linear trade-off between minimizing capacity expansion costs and maximizing reliability levels.”

“Although not all, many of the findings of the study have a high degree of generalizability to the context in tropical east Africa and other developing regions at large,” the paper concluded.

The Netherlands currently faces serious grid capacity issues, as more and more renewable energy projects, especially solar, are going online. Dutch grid operators and power generation asset owners are now taking a range of actions to reduce grid load and prevent PV curtailment.

With this in mind, researchers from Delft University of Technology (TU Delft) have looked at the impact of different penetration rates of electric vehicles (EVs), heat pumps, and PV generation on the Dutch grid. They analyzed the effects of these technologies on over-loading and nodal voltage deviations in different distribution grids and seasons.

“The authors acknowledge that grid impact assessment studies are highly dependent on the investigated grid specifications and case study characteristics,” the research group said. “Therefore, the results should not be straightforwardly generalized for all case studies, that investigate different distribution grids. Nevertheless, this work can provide valuable insights, especially in the case of the Netherlands.”

The academics used real data from Dutch distribution grid operators and categorized the country's different distribution networks as light-loaded rural grids, heavy-loaded rural grids, light-loaded suburban grids, heavy-loaded suburban grids, light-loaded urban grids and heavy-loaded urban grids. Using computer software, they simulated grid conditions with only PV and EV penetration, or only PV and heat pumps. They also took into account the combined penetration of PV, heat pumps, and EVs.

They set the penetration rates for the simulation at 50%, 80%, and 100%.

According to their findings, Dutch suburban areas are the most vulnerable to increased penetration of all technologies. In summer and winter, the suburban grids showed an overloading of up to 800%. As for line overloading, both suburban grids are overloaded from 50% total penetration, with heavy suburban grids having lines exceeding 700% overloading.

“The light suburban grid sees a voltage drop under 0.9 per-unit (pu) even from 50% penetration (once), while also once voltage drops under 0.85 pu at 100% penetration,” the academic said. “Multiple undervoltage incidents are observed in the heavy suburban grid at all three penetrations. Reaching up to 0.65 pu. and 0.42 pu at 80% and 100% penetrations, respectively.”

“The more frequent use of heat pumps for heating/cooling provokes a higher grid impact overall, but the longer EV charging periods provoke more long-lasting violations,” the researchers said. “The results have also been compared with results by aggregated data from databases, showing that bottom-up approaches present more pessimistic results than top-down approaches. However, the main insights remain similar.”

The researchers presented their findings in “Assessing the grid impact of Electric Vehicles, Heat Pumps & PV generation in Dutch LV distribution grids,” which was recently published in Applied Energy.

“The higher insulation and the improvement of the energy label of the future buildings are highly recommended for the minimization of the grid impact by the future electric heating,” they said.

Researchers from the Bern University of Applied Sciences (BFH) have proposed a series of measures to help solar PV increase its share in a given country's energy system without the need for building additional, costly distribution infrastructure.

In the “Discussion paper: Solution approaches for the grid integration of solar power,” the scientists explained that expanding the European grid, for example, would not solve the problem of having too much solar power injected into grids during load peaks, which may not be absorbed by the grid nor sold to consumers, due to the lack of enough demand.

“If we want to supply Italy with wind electricity from the North Sea, of course, we must increase the transmission capacity,” the research's lead author, Christof Bucher, told pv magazine. “However, at least in Switzerland, a lot of costs are associated with the distribution grid expansion to host more PV, which we think is the wrong way to push grid integration.”

The research group proposed a series of alternative measures that consumers and grid operators could employ to avoid grid expansion. They said a general incentive approach to grid-serving behavior should be encouraged.

For example, they claim that priority dispatch for PV may be avoided during peak times, thus forcing the PV system operators to use surplus solar power for batteries or electric vehicle (EV) charging. Priority dispatch has been an important tool to facilitate renewable energy integration into power systems in the past. It consists of prioritizing the injection of power produced by clean energy sources while offsetting conventional power production. 

“There should be no right to feed load peaks into the grid when they are not relevant in terms of energy but are challenging and uneconomical for the overall system,” the paper notes.

Increasing self-consumption by PV system owners should also be encouraged. “However, one thing technical is missing: Self-consumption does not necessarily reduce stress on the grid – that’s why many grid operators don’t agree with current regulations, which throughout Europe typically support self-consumption,” Bucher stated. “If you do self-consumption for 95% of the time, but one week per year you are on vacation and do not do any self-consumption, then the whole grid infrastructure must be dimensioned for this one week. It would be very easy to avoid this situation, but currently there are no incentives to do so.”

The researchers also warned that PV curtailment will be unavoidable in the future. “Curtailment should be used, but not too much,” Bucher explained. “Anyway, it should be an economic decision of every individual PV system operator. My guess is that today, 50% of distribution grid reinforcement investments are spent for maybe 10% of the additional solar energy. This is far from the economic optimum.”

According to him, encouraging a free market vision and reducing subsidies may be only part of the solution. “I guess it will not be sufficient as a free market would not necessarily give a price to the infrastructure,” he added. “Therefore, our short-term vision is rather a shift from kilowatt-only based feed-in tariffs (FIT) towards higher tariffs for systems that avoid injecting power peaks. As system operators don’t.”

He also explained that, by not injecting 50% of power, most systems lose less than 5-10% of energy, with self-consumption being taken into account. “If PV system operators are offered a 20% higher FIT for this sort of system control, they should take this offer,” he said. “And, of course, this could be implemented cost-neutral, with those who inject more power getting a lower FIT.

“In the view of the authors, it is more expedient to invest in the decentralized handling of power peaks than in the expansion of the distribution grid,” the paper concludes.

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.

Scientists need to put more effort and resources into developing deep-learning forecasting models that consider the morphology of PV panels, a group of academics led by the University of Cambridge said in a new paper.

Their work consists of a comprehensive review of advances achieved in the field of solar forecasting based on computer vision with deep learning. Computer vision is a special branch of artificial intelligence that helps computers to interpret and understand the world using digital images from cameras and videos. The deep-learning models and tools used with this approach are able to identify and classify objects.

“Integrating the solar panel spatial configuration and local shadowing effects caused by vegetation, buildings or terrain variation, has the potential to ameliorate the accuracy of solar forecasts,” the researchers explained. “This information could be inferred from irradiance measurements, object detection from sky images or high-resolution remote sensing observations, LiDAR data, and other in situ 3D mapping measurements.”

Another way to enhance deep-learning solar forecasting models recommended by the article is the introduction of the laws of physics. This could help with predictions of streamlines, which are paths that floating clouds trace in the atmosphere.

“Machine learning methods based on computer vision are capable of visualizing streamlines in satellite images and ground-based sky images but in a suboptimal manner,” the researchers said. “In this context, a physics-informed deep learning method has the potential to optimally visualize fluid mechanics field lines.”

The paper also suggests that the limited generalization skills of current deep-learning models are a strong limitation to their widespread implementation. However, the academics said this could be resolved by building models on many open-source data sets throughout the world.

The research group encourages future work to use a standard benchmark data set, as that will help to compare different models.

“Although there are studies benchmarking certain types of solar forecasting models based on a single dataset, there are currently very limited studies cross-comparing different types of solar forecasting models, i.e., deep learning-based models, machine learning-based models, timeseries models, and physics deterministic models on standardized datasets,” they said.

The researchers presented their findings in “Advances in solar forecasting: Computer vision with deep learning,” which was recently published in Advances in Applied Energy. The group includes scientists from the European Space Agency, ENGIE Lab, University of California Santa Barbara, Stanford University, Idaho National Laboratory, Open Climate Fix, the US National Renewable Energy Laboratory (NREL), Réseau de Transport d’Électricité, the World Energy and Meteorology Council, and University College Dublin.

The research group concluded by calling for better coordination between commercial forecast developers and grid operators.

“This is a significant barrier that can, however, be overcome by putting effort into understanding the needs and processes of the user (i.e., grid operators) on the one side and developing the products with the users on the other side,” they said. “Further, grid operators might need to upgrade their skills via dedicated training to gain the required knowledge to understand and use recent computer vision-based forecasting models.”

Researchers at Sweden's Uppsala University have applied deep machine learning to automatically identify photovoltaic and solar-thermal systems in aerial imagery and said their work yielded mixed results.

They looked specifically into ariel imagery from Sweden by using a deep learning framework called DeepSolar CNN, which was developed by Stanford scientists. The framework uses a convolutional neural network (CNN), which enables extracting and learning features from visual data.

According to the research group, the proposed framework achieved an accuracy of 63.9% when used over a Swedish data set. That is lower than previous research conducted with the same framework in other countries. For example, a US group of researchers attained an accuracy of 91%, and a study done in Germany achieved 87.3%.

However, the Swedish-trained CNN has achieved more competitive results regarding the recall rate. While the precision rate refers to the method's ability not to make mistakes, the recall rate refers to its ability not to let positive information slip through. In that recall metric, the Swedish DeepSolar has achieved 81.8%, compared to 98.1% in the US and 87.5% in Germany.

“Regarding the lower precision achieved in this study compared to the previous publications, one explanation is that our scans of complete municipalities in the sparsely populated Sweden contain a much larger share of negative images than the mentioned studies,” the scientists explained. “As the main goal is to evaluate how useful detection of decentralized solar energy systems (SESs) by aerial images and a CNN classification algorithm are for creating as comprehensive a database as possible, a high recall is more important than a high precision.”

The scientists said the algorithm was first trained with a data set from North-Rhine Westphalia state in Germany and was then fine-tuned to Sweden with pictures from eight municipalities. It was then used to scan the whole spatial area of three Swedish municipalities – Uppvidinge, Falun, and Knivsta. These data were compared with other data collected with onsite inspections.

This iterative process involved multiple scans, with the CNN algorithm being retrained after each municipality scan, resulting in progressively enhanced accuracy. In the initial scan, the algorithm detected 89% of the detectable PV systems (excluding BIPV and vertical installations) and 59% of the ST systems,” the scientists emphasized. “Remarkably, by the fourth and final scan, these detection rates improved to 95% for PV systems and 80% for ST systems.”

They also specified that most undetected PV systems were frameless modules, typically installed on darker-colored roofs. In addition, shading from trees or structures, image reflections, and systems with high tilt angles impeded the classification algorithm's detection efficacy.

“Accuracy underscores the model's ability as both an inventory tool and a mechanism for constructing comprehensive databases of existing SESs,” the Swedish team concluded. “Connecting such a database, where the exact locations of the SESs are known, to existing building and property inventories, facilitates the generation of remarkably detailed SES market segment statistics.”

Its findings can be found in the paper “Mapping of decentralized photovoltaic and solar thermal systems by remote sensing aerial imagery and deep machine learning for statistic generation,” published in Energy and AI.

In the ever-evolving world of solar energy applications, access to accurate and reliable modeled irradiance data is crucial. Modeled irradiance data based on satellite products and numerical weather prediction models are frequently used. Many of such sources of data are offered by institutional or commercial providers. However, it is difficult and time consuming for users to independently identify the best provider for their specific application and location.

Benchmarking Solar Data

In our Task 16 report “Worldwide Benchmark of Modelled Solar Irradiance Data” we address this challenge. The report presents a benchmark of model-derived direct normal irradiance (DNI) as well as global horizontal irradiance (GHI) data that considers 129 globally distributed sites where ground-based radiation measurement stations are or have been installed. DNI and GHI estimates are compared against high-quality observations from these stations. The performance of the modeled data is analyzed with respect to different regions and climate zones. This study helps the solar industry make better informed decisions about solar resource assessments.

Building a reference database

Big efforts were made to build the reference database. We finally used data from 25 different providers with 129 stations during 2015–2020. Only quality-assured data has been considered in this benchmark through a comprehensive set of best practices and newly implemented quality-control procedures. These include automatic as well as manual data quality-control tests carried out by a team of experts led by CSP Services GmbH for all stations and result in flags describing the quality for each time stamp. The bulk of the quality-controlled data, covering all continents and many climate zones, has been published within this benchmark.

Global representation

One of the strengths of this benchmark is its global reach. The 129 ground-based stations are strategically distributed worldwide, encompassing diverse regions and climate zones. This global representation includes 31 stations in Africa, 31 in Asia, 27 in North America, 20 in Europe, 13 in Australia, 5 in South America, and even 2 in Antarctica. By spanning such a wide geographical scope, this benchmark provides insights into the performance of model-derived data in various environmental conditions, from arid deserts to polar extremes

Assessing model-derived data

Ten different models were tested, although not all provide estimates for all stations. Amongst other statistical performance parameters, the mean bias deviation, root mean square deviation, and standard deviation are calculated for each year and per station. The results for the relative mean bias deviation affecting GHI are shown in Figure 1.

Benchmark findings

Based on the results of the statistical analysis, the most appropriate dataset might depend on site, climate, or continent of interest. The model errors and the differences between the various modeled datasets are much higher for DNI than for GHI.

Figure 1: Relative mean bias deviation (rMDB) for GHI and all stations and years. Magenta color indicates results out of the color bar range. The point size corresponds to the total number of datapoints in the tested data from 2015 to 2020.

Solar irradiance measurements and time series play a decisive role in supporting solar resource assessments, especially for medium and large PV installations. Not only they represent the foundation of solar resource assessment and forecasting, but they also drive prospective PV yield studies, and can be used as a calibration reference when using satellite data, evaluating PV systems’ performance, or developing forecasting algorithms.

Challenge: data gaps

However, such datasets inevitably have gaps – periods with missing data – as a result of defaults during data-logging, sensor failures or quality check procedures that can compromise their applicability and value. An additional issue is that data gaps can be further enlarged when computing temporal aggregations, notably for intra-daily to daily, daily to monthly and yearly averages, thus further degrading the dataset.

This has raised the need for gap-filling methods that can post‑process either static historical datasets or more dynamic real-time data streams. Each case is characterized by different constraints, such as the access to data that follows a given data gap or the acceptable time lag for generating the replacement synthetic data.

Benchmark for GHI gap-filling methods

In our report “Framework for Benchmarking of GHI Gap-Filling Methods”, led by Mines Paris PSL, we propose a gap-filling benchmark framework and evaluate a set of possible baseline algorithms for intra-hourly and daily sums of GHI time series. Five methods have been compared for different lengths of gaps: Nearest neighbors, linear interpolation, two machine learning approaches and use of satellite data. For short gaps linear interpolation works best, as for longer gaps the use of satellite data is suggested.

Conclusion

With access to comprehensive statistical performance parameters and insights into model errors, analysts can make informed decisions about which data providers and models align with their needs. Our recently published reports serve as a guiding light, making the uncertainty of data and models comparable for solar industry professionals and researchers, ultimately advancing the field and promoting sustainable energy solutions worldwide.

This article is part of a monthly column by the IEA PVPS programme. It was contributed by IEA PVPS Task 16 – Solar Resource for High Penetration and Large Scale Applications. Further information can be found in Task 16’s recent reports: https://iea-pvps.org/research-tasks/solar-resource-for-high-penetration-and-large-scale-applications/

By Jan Remund, Meteotest AG, Switzerland

With 80% of the world’s population without access to electricity resides in Sub-Saharan Africa — it is clear that the current fossil fuel based energy system fails to meet Africa’s power needs. Something needs to be done quickly.

Renewables offer a compelling solution. Not only are they the most rapidly deployable and versatile technology available. They are also the most affordable.

A recent analysis by the International Renewable Energy Agency (IRENA) shows that the adoption of renewable power in Africa since the year 2000 has led to USD 19 billion in fossil fuel cost savings within the electricity sector.

Given that Africa’s renewable energy potential far outstrips its projected demand for electricity in 2040, the continent has more than enough renewable resources to promote inclusive growth and sustainable development as envisioned by the African Union in its Agenda 2063.

Africa’s renewable energy resource potential, however, is unevenly distributed across the continent. There is a profound need for appropriate infrastructure to be put in place to utilize and distribute this potential among the different regions to enable efficient, sustainable, and affordable access to energy across Africa.

To realize Africa’s vast potential, we must ensure there is adequate investment and infrastructure development to support renewable energy. In the coming years, this means urgently overcoming the structural barriers across three priorities: infrastructure, policy, and institutional capabilities.

Continued investments in cross-border transmission infrastructure and a deepening of electricity trade can bring more flexibility to achieve a smart diversified generation structure and accommodate the high share of variable renewables, thus enhancing Africa’s grid reliability and resilience.

To achieve this transformation, in 2021 the African Union launched the African Single Electricity Market (AfSEM) aimed at creating one of the largest electricity markets in the world by 2040.

The Continental Power System Masterplan (CMP), under which IRENA collaborates with AUDA-NEPAD, serves as a blueprint and supports the establishment of a long-term continent-wide planning process for power generation and transmission involving all five African power pools.

Implementing this ambitious plan will be a herculean task, requiring an extraordinary level of financial resources—a burden that African nations cannot shoulder alone.  As Kenya’s President William Ruto made clear at the recent launch of the Accelerated Partnership for Renewables in Africa (APRA), which IRENA facilitates, the question is not whether Africa has the ambition, but how to translate ambition into reality.

The energy transition requires large public investment to trigger systemic change and build the physical infrastructure needed to develop a new energy system powered by renewables. This is where multilateral financial institutions come into play.

For too long, institutions have addressed symptoms rather than root causes. While funding individual projects—be they utility-scale or off-grid—is crucial, without the necessary structural changes, this approach is not comprehensive. It cannot hope to attract sufficient capital to fundamentally transform the continent’s energy reality to deliver its socioeconomic development goals. A change in approach is needed.

It is time to reimagine how multilateral cooperation works and to strengthen collaboration between the Global North and the Global South. Reform is needed to the way lending is made. Priority must be given to building supportive physical infrastructure, enhancing local capacities, and creating local supply chains leveraging Africa's abundant critical materials. All of this must be done in a way that adds economic value for African countries.

Only 2% of global investments in renewable energy in the last two decades were made in Africa. The recent initiative announced by the COP28 Presidency during Africa Climate Week marks a significant milestone for the continent. Not only is the USD 4.5 billion commitment to develop clean power in Africa a significant sum, it is also targeted to address key energy transition barriers, including the continent’s infrastructure needs.

Later this year, at COP28, the first Global Stocktake since the Paris Agreement will be held in the United Arab Emirates. This event will measure the gap that remains between climate pledges and action. The moment, however, will also present us with a chance to chart a new course.

As we approach this pivotal moment in history, it is imperative that we construct an action-oriented narrative that tackles the key barriers. Doing so will enable us to take meaningful strides towards keeping the 1.5-degree Celsius temperature rise within reach.

Authors: Francesco La Camera, IRENA Director-General & Nardos Bekele-Thomas, AUDA-NEPAD CEO

This opinion piece first appeared in The Standard on 11^th September 2023

Turkey has started talks with the United Arab Emirates to produce hydrogen and construct an offshore wind facility in Mediterranean waters. “We have a great potential in renewable energy, especially solar and wind,” Turkish Energy Minister Alparslan Bayraktar reportedly said. On social media, he outlined Turkey's energy goals: 42,000 MW of solar, 18,000 MW of wind, and 5,000 MW of offshore wind power by 2035. He also emphasized Turkey's focus on technology transfer in negotiations with Russia for a second nuclear power plant.

TotalEnergies and Air Liquide have signed an agreement for the long-term supply of green and low-carbon hydrogen to a TotalEnergies refining and petrochemical platform in Normandy, France. Air Liquide will build and operate the Normand'hy electrolyzer, with a total electrical capacity of 200 MW. TotalEnergies will supply around 700 GWh/year of “renewable and low carbon power” to the Air Liquide electrolyzer for half of its capacity.

TotalEnergies has also launched a call for tenders to supply 500,000 tons per year of green hydrogen by 2030. The French energy company will use it in its six European refineries in Antwerp (Belgium), Leuna (Germany), Zeeland (Netherlands), Normandy, Donges, and Feyzin (France), and its two biorefineries in La Mède and Grandpuits (France).

Everfuel has decided to prioritize green hydrogen production capacity development and reduce refueling network investments by high-grading its existing portfolio of refueling stations and projects. It said the decision follows a realignment of strategy, with a new focus on scaling green hydrogen production “to capture significant value creation opportunities led by recent market developments in Germany and Denmark.”

Texas-based Sage Geosystems has announced field results from its full-scale commercial pilot project. It has found that its EarthStore energy storage system can provide 18 hours or more of storage capacity to effectively generate baseload power 24/7 when paired with solar or wind generation.

The data sets were obtained by pumping in and flowing back water from a well to gauge capacity and power duration. According to the company, no induced seismicity was measured either during fracturing or subsequent pumping operations.

The pilot plant has demonstrated that it can also provide high-powered, short-duration power during peak demand.

“Both storage intervals, long- and short-duration, enhance grid reliability with stable power output,” the company reported. “In addition, the heat from the formation expands the fluid downhole and improves round trip efficiency.”

Sage has developed an underground energy storage technology which can provide both short- and long-duration storage. The system harvests the pressure energy of a fluid while using  geothermal power from any underground formation where the required heat level exists to enhance its operation. The company is targeting lower temperatures (100 C to 250 C) at depths of three to 6 kilometers.

According to Sage, its EarthStore energy storage design is ready to scale and is not geographically limited. In addition, it can be used in newly drilled wells and in existing oil and gas wells.

The company has also reported that based on the levelized cost of storage (LCOS), EarthStore can provide power at a cost that is lower than lithium-ion battery storage and traditional pumped storage hydro.

“It also is competitive with natural gas peaker plants, providing a cleaner option for providing ancillary services, black start services, and/or redistributing curtailed energy during peak demand periods,” Sage said. However, the company didn't provide any hard figures for LCOS.

Other reported results of the pilot project are as follows:

• Produced 200 kW for over 18 hours (long duration) and 1 MW for 30 minutes (load following), limited only by the small-diameter rental surface equipment piping
• Generated electricity with Pelton turbines to power equipment on location
• Measured subsurface system efficiencies between 88% to 94%, with an estimated round-trip efficiency (RTE) of 70% to 75%
• The heat from the formation expands the downhole fluid and improves RTE
• Measured fluid losses greater than 2%, decreasing to 1% by the end of the five-week period
• Demonstrated the ability in a single well to generate 2 MW to 3 MW of net output

“We have cracked the code to provide the perfect complement to renewable energy, yielding reliable alternative baseload in a manner that is cost competitive with lithium-ion batteries and natural gas peaker plants,” said Cindy Taff, CEO of Sage Geosystems. “The opportunities for our energy storage to provide power are significant – from remote mining operations to data centers to solving energy poverty in remote locations. We can interconnect with power grids or develop island/microgrids with a cleaner energy solution that is proven and ready to scale.”

The levelized cost of electricity (LCOE) for agrivoltaic bifacial systems based on single-axis trackers is 23% lower than that of agrivoltaic bifacial facilities built on fixed structures, a new study from KU Leuven in Belgium has shown.

“Our cost estimations for this pilot study, revealed similar expenses for both fixed and tracked systems,” the research's lead author, Brecht Willockx told pv magazine. “However, due to the significantly higher specific yield (kWh/kW), the solar tracker exhibited a lower LCOE.”

The researchers conducted a comprehensive comparison between the two system configurations at a testing field located in Grembergen, Belgium, with both systems using the pile drilling technique for their foundations.

The system with the fixed structures was deployed with a row-to-row distance of 9 m to maintain appropriate spacing for crop growth and accessibility. The solar modules have each a nominal power of 455 W and are placed at a maximum height of 2.6 m to minimize any visual impact.

As for the system relying on trackers, the same module types were placed at a height of 2.3 m. “To enhance bifacial gain, the structural elements at the backside are minimized by increasing the gap between the torque tube and module (50 cm) and ensuring longitudinal module spacing (1 cm),” the scientists explained.

Through their analysis, the academics found that the facility based on trackers outperformed the fixed structure setup in energy yield, resulting in approximately a 35% increase in monthly electricity production. Furthermore, the system using tracking showed improved results in land use efficiency, which takes into account both electrical and agricultural yields.

The Belgian group found that, in the rain-fed 2021 season, the tracking system has achieved 15% more total yield. In the same season, the fixed system achieved a 5% lower yield, meaning it was no better than separate production sites. In the dry 2022 season, the tracked system displayed a 47% increase in total yield and the fixed one an increase of 21%, compared to the reference point.

Throughout the rainy growing season of 2021, a smart tracking algorithm, taking into account a trade-off between energy yield and crop yield, was employed, while in the hot and dry season of 2022, the system switched to a traditional full energy tracking algorithm, taking into account only energy yield.

The LCOE for the fixed system constructed by the researchers was found to be €0.10/kWh ($0.107/kWh), while the system with tracking algorithm was €0.077/kWh.

According to the research, those prices hike a bit when considering the crop yield losses that are due to the installation of the PV systems on the field. An additional €0.02/kWh is to be added to the LCOE of the tracked system therefore, while a €0.035/kWh is to be added in the case of the fixed system.

“We believe that the best business model for farmers, investors, and off-takers are power purchase agreements (PPA) contracts, where prices of interspace agrivoltaics are in line with ground-mounted PV,” Willockx added. “However, there is still a significant premium due to the lower installed capacity per hectare and fixed costs.”

The scientists presented their findings in the paper “Performance evaluation of vertical bifacial and single-axis tracked agrivoltaic systems on arable land,” which was recently published in Renewable Energy. “Practical insights and limitations of agrivoltaic systems have been incorporated into the evaluation,” Willockx said.

Starting in 2024, all new solar and wind plants in The Netherlands with a capacity greater than 1 MW will be required to enable communications between the grid and energy assets through a so-called real-time interface (RTI).

This measure is intended to improve the grid congestion issues that have been threatening the deployment of additional renewable energy capacity over the last three years and has forced all operators to take measures and seek creative solutions to reduce the grid's burden.

The RTI has to be compliant with the International Electrotechnical Commission 61850 standard, which defines communication protocols for intelligent electronic devices at electrical substations. The requirement is in line with the framework established by the European Commission Regulation (EU) 2016/631.

One of the first Dutch vendors with a stand-alone RTI solution for PV plant operators is Withthegrid. Its Teleport product has been approved in lab tests by Norwegian classification society DNV on behalf of Netbeheer Nederland, the Dutch association of national-regional electricity and gas network operators. It is now being validated in the field by the three main grid operators, according to Paul Mignot, CEO, Withthegrid.

The Teleport is compatible with a number of brand-name inverters. It can also be connected to a battery system, wind turbines, and metering equipment. It uses standard data communications cabling, such as RS232, RS485, or Ethernet cables. It includes relevant protocols, such as Modbus, Open Charge Point Protocol, and SunSpec, which are used in inverters, electric vehicle chargers, and battery systems. It comes equipped with European-grade security and encryption, including no inbound communication channels.

The device sits between the endpoint of the distribution system operator (DSO) and the central PV inverter. It receives grid congestion signals from the DSO endpoint to limit power production, or balancing market signals from the transmission system operator (TSO), and it can then send commands, such as “limit production power” to the central inverter in a PV plant based on the owners' parameter settings.

From the grid perspective, it contributes to a balanced grid and greater safety of infrastructure. For plant operators, it makes it possible to ramp up and ramp down production within seconds, according to Mignot.  “This kind of flexibility on the part of the asset owner avoids waste and financial losses,” Mignot told pv magazine.

Siemens has an RTI-compliant product that has similarly been approved for field trials, according to the website of Netbeheer Nederland.

The Netherlands urgently needs to address grid constraints, as high volumes of solar capacity will be deployed in the years ahead. Over the past two years, Liander has implemented a number of measures to increase grid capacity in several areas facing grid constraints, as such bottlenecks are preventing more renewables from going online. These measures include the deployment of two giant transformers and congestion management for grid bottlenecks.

Tennet also recently developed an interactive online map showing the locations in the country where the power grid is most congested.

Dutch power and gas supplier Liander recently revealed this week that residential PV system owners experienced three times as many curtailment events in the first half of 2023 than they did in the same period last year in the provinces of Gelderland, Noord-Holland, Flevoland, Friesland, and Zuid-Holland.

As of June 2022, the Netherlands had a cumulative installed PV capacity of 16.5 GW, with 3,803 MW installed in 2021 and 3,882 MW installed in 2022, according to CBS, the nation's statistics agency.