Spain installed 1.14 GW of solar capacity for self-consumption in 2025, lifting cumulative capacity to 9.3 GW, as residential and commercial installations declined while industrial and off-grid segments showed greater resilience, according to data from the Spanish Photovoltaic Union.
Solar self-consumption capacity in Spain reached a cumulative 9.3 GW in 2025, according to data from the Spanish Photovoltaic Union (UNEF).
Spain added 1,139 MW of new self-consumption capacity during the year, representing a 3.7% slowdown compared with 2024. UNEF said the deceleration signals a phase of market stabilization following several years of rapid growth.
The residential segment accounted for 229 MW across 36,330 new installations, a year-on-year decline of 17%. UNEF attributed the contraction to the phase-out of tax incentives linked to energy-efficient home renovations and lower compensation for surplus electricity exported to the grid under deregulated market contracts.
UNEF said falling surplus compensation prices are reducing the attractiveness of oversized systems designed primarily for grid injection. As a result, demand is shifting toward installations optimized for instantaneous self-consumption. The association is calling for revisions to the simplified regulated compensation mechanism to enable broader settlement of surplus energy and improve economic signals for small-scale systems.
The commercial segment installed 176 MW in 2025, down 15% from the previous year. Collective self-consumption remains limited despite its potential to optimize shared generation and demand. Industry representatives said pending regulatory updates are needed to enable aggregated management models, dynamic energy allocation, and an expansion of eligible self-consumption areas.
Industrial self-consumption installations totaled 679 MW, marking a slight increase compared with 2024. UNEF said growth in this segment is being driven by larger medium-voltage systems aimed at reducing electricity costs and partially covering electrified thermal demand. Project viability increasingly depends on tariff structures with a higher variable component and more streamlined permitting for medium-sized installations.
Off-grid installations reached 55 MW in 2025, reflecting growing uptake of hybrid solar-plus-storage systems in rural areas and locations without grid access. Battery integration in grid-connected installations also continued to rise, improving controllability of generation and supporting system flexibility.
UNEF said Spain will need to deploy an average of around 2 GW of self-consumption capacity per year to meet the 19 GW target set out in the country’s National Integrated Energy and Climate Plan. Achieving that level will require regulatory stability, administrative simplification, and more effective integration of distributed energy storage.
54% of respondents cited “energy availability and redundancy” as the single greatest obstacle to successful data center development between now and 2030.
aw firm Foley & Lardner LLP released today its 2026 Data Center Development Report, focusing on the growth and challenges in the data center boom that aims to sustain the growth in AI and LLM usage.
A major focus was on energy, with 54% of respondents citing “energy availability and redundancy” as the single greatest obstacle to successful data center development between now and 2030.
Want to learn more about matching renewables with data center demand?
The event will spotlight how solar and energy storage solutions are driving sustainable and reliable infrastructure, with a particular focus on powering the country’s rapidly growing data center sector.
In terms of the right energy mix for data centers, 55% of respondents agreeing that the ideal energy mix to meet the growing power demand of data centers is largely renewables (41%), followed by natural gas (17%), nuclear (16%), and BESS (14%).
Nearly half (48%) of industry participants named advances in energy efficiency (which often includes storage optimization) as the greatest opportunity for development through the end of the decade, and nearly three in four respondents (74%) said advanced energy storage systems like batteries, hybrid solutions, and microgrids are the best way to ensure energy resilience.
Only 14% of developers are actually pursuing modular and small modular nuclear reactors as a viable energy opportunity.
Intriguingly, 63% anticipate a “strategic correction” in the market by 2030, driven by the intense competition for power, with one unnamed banking executive in the report saying, “Once power runs out in 2027 or 2028, that’s where we think deal flow will start to slow down.”
105 U.S.-based respondents were qualified to participate in the survey, including those who had direct experience in data center development, energy procurement, technology delivery, or operations within the past 24 months.
Daniel Farris, partner and co-lead of Foley’s data center and digital infrastructure team: “There is a Gold Rush mentality right now around securing power. That’s a big part of why people feel there’s a bubble,” said “There’s going to a period in the next two to three years where power at necessary levels is going to be really hard to come by.”
Rachel Conrad, senior counsel and co-lead of Foley’s data center and digital infrastructure team: “Over the next five to 10 years, power providers will need to either grow capacity or increase efficiency to meet the demand fueled by data centers.”
Brazil curtailed about one-fifth of its solar and wind generation in 2025, wasting an estimated BRL 6.5 billion ($1.23 billion), as grid constraints and demand mismatches pushed the power system close to operational safety limits on 16 days, according to a report from Volt Robotics.
Brazil failed to use roughly 20% of the solar and wind electricity it generated in 2025, resulting in an estimated loss of BRL 6.5 billion, according to Volt Robotics’ Annual Curtailment Report.
Volt Robotics said the scale of curtailment reflects an unprecedented period of renewable oversupply combined with operational constraints in Brazil’s national electricity system.
Average generation cuts reached 4,021 MW over the year, equivalent to the monthly output of a large hydroelectric plant. On at least 16 days in 2025, system operation approached the lower technical safety limit, a sharp increase from 2024, when only one comparable event was recorded.
Volt Robotics said the 2025 events were driven by excess electricity supply rather than scarcity, marking a structural shift in system risk dynamics.
Curtailment intensified between August and October, when historically high levels of generation coincided with transmission constraints and weaker demand. The report attributes the peak losses to a combination of operational limitations, grid congestion, and insufficient flexibility to absorb surplus power.
Sunday mornings emerged as the most frequent stress point for the grid. Volt Robotics said reduced economic activity during weekends lowers electricity demand, while solar output peaks and is often reinforced by strong wind generation. This recurring mismatch leads to network overloads, forced generation cuts, and system operation near the lower safety threshold.
The report also highlights the risk of system instability caused by excess renewable generation. During the 16 critical days, Brazil’s National System Operator classified conditions as severe and implemented emergency measures, supported by the National Electric Energy Agency, including extraordinary generation curtailments.
Volt Robotics warned that without structural adjustments, surplus clean energy itself can become a source of operational risk.
The economic impact extends beyond immediate revenue losses. Frequent curtailment increases perceived investment risk, raises financing costs, and weakens Brazil’s appeal for new renewable energy projects, the report said. Both regulated and free-market projects were affected, with exposure to contractual penalties and the Settlement Price of Differences.
Regionally, Minas Gerais, Ceará, and Rio Grande do Norte recorded the highest levels of curtailed energy, forming what Volt Robotics described as Brazil’s “curtailment triangle.” Southern states experienced significantly lower losses.
Volt Robotics said the situation reflects a structural mismatch between rapid renewable capacity expansion, rising distributed generation, transmission bottlenecks, and tariff structures that do not adequately signal when electricity consumption is most valuable.
The report recommends the introduction of more dynamic time-of-use tariffs, stronger demand-side participation, and regulatory reforms to reduce curtailment and maintain the stability of Brazil’s electricity system.
French researchers have developed a high-resolution computational framework to model microclimate effects of large floating solar PV systems, enabling accurate predictions of heat transfer, ambient temperatures, and water evaporation based on panel configuration and wind conditions. The model can inform thermal performance, environmental impacts, and optimize designs for utility-scale floating PV, as well as ground-mounted and agrivoltaic installations.
French researchers have developed a framework to model microclimate effects of large-sized floating PV systems.
The new model can be used to determine wind-dependent convective heat transfer coefficients (CHTC), ambient temperatures, and to estimate evaporation patterns in partially covered bodies of water based on a variety tilt angles, module heights, and pitch distances.
“The main novelty of this work lies in the numerical methodology we developed, specifically an upscaling method to quantify panel-atmosphere interactions at the module scale then model the micrometeorology at the power plant scale with a relatively fine resolution of about 4 meters,” Baptiste Amiot, corresponding author of the research told pv magazine, adding that the resolution is significantly higher than others in this field.
“Applying this methodology enables us to map the thermal performance across utility-scale installations and to provide insights into local environmental effects, such as evaporative losses,” he said.
The precursor model is geometrically adaptable: tt can handle various tilt angles, mounting heights, and inter-row spacings, according to Amiot. “It is particularly well-suited for large-scale installations exposed to sufficiently windy conditions,” Amiot added.
The researchers used a computational fluid dynamics (CFD) precursor model, a microclimate CFD model supporting the PV parameterization, and an experimental survey. A wind-tunnel setup typical of a land-based application was used to confirm accuracy of altitude-based wind profiles.
In addition, a geometrical layout of a commercial floating PV (FPV) installation was used for the atmosphere boundary layer parameters. The wind direction effects were assessed using the microclimate CFD model that reproduced the localized conditions of the commercial FPV array.
“The atmospheric component is fundamentally similar to regional climate models (RCMs) but deploying it within a CFD framework offers advantages in terms of surface element parameterization and the spatial discretization we can achieve,” said Amiot.
Some of the findings included temperature gradients range between 1.3 C/km and 5.8 C/km; headwinds and tailwinds relative to the front surface of the PV modules generate the greatest turbulence levels. Furthermore, the team was able investigate how turbulent flows influence water-saving gains based on PV coverage of the water surface.
Assessing the results, the researchers noted that the precursor method “readily determines” heat transfer coefficient correlations as a function of wind speed and direction. “This is essential to obtain the thermal U-values that govern panel cooling,” added Amiot.
The model can be extended to model large ground-mounted systems and agrivoltaics, including dynamic configurations where panels adjust orientation throughout the day, according to Amiot. It is suitable for inland and nearshore FPV, but not offshore FPV.
The researchers are currently focused on developing CFD models to predict both the energy output and environmental trade-offs of dual-use photovoltaics systems and FPV evaporation research at finer spatial scales, coupled with in-situ measurements. It is also working on an agrivoltaics CFD-plant model to predict crop response below PV canopies.
After hitting an all-time high of $121.65/oz on Jan. 29, silver prices have tumbled to $79.44/oz, with analysts warning of a potential drop toward $50/oz.
After reaching an all-time high of $$121.65 per ounce (oz) on Jan. 29, silver prices have fallen sharply in recent days, dropping to $79.44/oz this morning.
The downturn had been anticipated by two analysts interviewed by pv magazine on Jan. 27, who warned that the steep rally seen in previous weeks could reverse abruptly in the days ahead.
One of the two analysts, Mike McGlone, senior commodity strategist at Bloomberg Intelligence, said the price could stabilize around $50/oz, although he did not provide a timeframe for when this new trend might materialize.
“Reversion toward $50 appears as a normal path for the commodity known as the ‘devil's metal' due to its volatility,” he told pv magazine.
Rhona O’Connell, head of market analysis for EMEA and Asia at StoneX, said on Jan. 27 that investors might soon rethink their rush into silver. She explained that speculative buying had pushed the metal into risky territory, making prices vulnerable to a sharp correction. O’Connell also said fears of potential U.S. tariffs fueled the recent rally, swelling COMEX inventories as metal flowed into the U.S. Further gains are unlikely, she added, dismissing even $100/oz as unsustainable and warning of a potentially severe price reversal.
Silver prices surged by approximately 130% in the past six months and around 243% over the past year. The average silver price was $28.27/oz in 2024, $23.38/oz in 2023, and $21.80/oz in 2022.
Renewables and storage could reliably power data centers, but success requires active grids, coordinated planning, and the right mix of technologies. Hitachi Energy CTO, Gerhard Salge, tells pv magazine that holistic approaches ensure technical feasibility, economic viability, and energy system resilience.
As data centers grow in size and complexity, supplying them with cheap and reliable power has never been more pressing. Gerhard Salge, chief technology officer (CTO) at Hitachi Energy, a unit of Japanese conglomerate Hitachi, shed light on the relationship between renewable energy and data center operations, noting that while technically feasible, success requires careful planning, the right infrastructure, and a holistic approach.
“When we look at what's happening in the grids, then renewables are an active element on the power generation side, and the data centers are an active element on the demand side,” Salge told pv magazine. “What you need in addition to that is in the dimensions of flexibility, for which we need storage and a grid that can actively act also here in order to bring all these elements together.”
Want to learn more about matching renewables with data center demand?
The event will spotlight how solar and energy storage solutions are driving sustainable and reliable infrastructure, with a particular focus on powering the country’s rapidly growing data center sector.
According to Salge, the key is active grids, not passive systems that simply react to conditions. With more renewables, changing demand patterns, new load centers, and storage options like batteries and existing facilities such as pumped hydro, it is crucial to coordinate these resources actively to maintain supply security, power quality, and cost optimization.
“But when you talk about the impact and the correlation between renewables and data centers, you need always to consider this full scope of the flexibility in a power system of all the elements—demand side, generation side, storage side, and the active grid in between,” he said, noting that weak or congested grids would not serve this purpose.
AI data centers
Salge warned that not all data centers are the same. “There are conventional data centers and AI data centers,” he said. “Conventional data centers are essentially high-load systems with some fluctuations on top. They contain many processors handling requests—from search engines or other applications—so the workload is distributed stochastically across them. This creates a baseline load with random ups and downs, which is the typical load pattern of a conventional data center.”
AI workloads, in contrast, rely heavily on GPUs or AI accelerators, which consume significant power continuously. Unlike conventional data centers, AI data centers often run at sustained high load, sometimes close to maximum capacity for long periods.
Htitachi Energy CTO Gerhard Salge
Image: Hitachi Energy
“AI data centers are specifically good in doing parallel computing,” Salge explained. “So many of them are triggered with the same demand pattern at the same time, which creates these spikes up and down in the demand profile, and they come in parallel all together.”
These fluctuations challenge both the power supply and the voltage and frequency quality of the connected grid. “So, you need to transport active power from an energy storage system or a supercapacitor to the demand of the AI data center. And that then needs to involve really the control of the data center’s active power. What you need is the interaction between the storage unit and then the AI data center to provide active power or to absorb it afterwards when the peak goes down. That can be also done by a supercapacitor.”
Batteries can store much more energy than supercapacitors, but the latter can ramp smaller energies more frequently. “However, if you put a battery that is smaller than the load, and you really need to cycle the battery through its full capacity, the battery will not survive very long with your data center, because the frequency of these bursts is so high, then you are aging the battery very, very quickly, yeah, so supercapacitors can do more cycles,” Salge emphasized.
He also noted that batteries and supercapacitors are both mature technologies, but the optimal setup—whether one, the other, or a combination with traditional capacitors—depends on storage size, number of racks, voltage levels, and overall system design.
Managing AI training bursts
Salge stressed the importance of complying with grid codes across geographies. “You need to become a good citizen to the power system,” he said. “You have to collaborate with local utilities to make sure that you are not infringing the grid codes and you are not disturbing with the data center back into the grid. A good way to do this, when renewables and data centers are co-located, is to manage renewable energy supply already inside the data center territory. Moreover, having a future-fit developed grid is a clear advantage. Because you have much more of these flexibility elements and the active elements to manage storage and renewable integration and to manage the dynamic loads of the data centers.”
If the grid is not future-fit with modern, actively operating equipment, operators will see significantly more stress. “With holistic planning, instead, you can even use some of the data center flexibility as a controllable and demand response kind of feature,” Salge said, adding that data center operators could coordinate AI training bursts to periods when the power system has more available capacity. This makes the data center a predictable, controllable demand, stressing the grid only when it is prepared.
“In conclusion, regarding technical feasibility: yes, it’s possible, but it requires the right configuration,” Salge said.
Economic feasibility
On economics, Salge believes solar and wind remain the cheapest power sources, even when accounting for the grid flexibility needed to integrate them with data centers. Solar is fastest to deploy, wind complements it well, and both can be scaled in parallel.
“Any increase in data center demand requires investment, whether from renewables or conventional power. Economics depend on the market, and market mechanisms, regulations, and technical grid planning are interconnected, influencing energy flow, pricing, and system stability,” he said.
“We recommend developers to work with all stakeholders—utilities, technology providers, and planners—from the start to ensure reliability, affordability, and social acceptance. Holistic planning avoids reactive fixes and leads to better long-term outcomes,” Salge concluded.
Bulgaria installed over 1 GW of solar for the third consecutive year in 2025 and is forecast to add over 2 GW this year thanks to a large pipeline of utility-scale projects.
Bulgaria added 1,416 MW of solar last year, according to official data published on the ENTSO-E Transparency Platform. The result marks the third consecutive year Bulgaria has deployed over 1 GW of solar and takes the country’s cumulative capacity to 5,984 MW.
Desislava Mateva, project manager at the Sofia-based Association for Production, Storage and Trading of Electricity (APSTE) told pv magazine that Bulgaria’s solar market is currently dominated by ground-mounted, utility-scale solar plants, reflecting the availability of land, strong developer activity and increasing access to project finance.
Utility-scale solar made up around 90% of Bulgaria’s new capacity last year. Mateva said the market was driven by the strong commercial competitiveness of solar, making projects viable without direct subsidies, as well as active support from local and international banks and a large pipeline of development projects that reached the ready-to-build stage or financial close over the past 18 months.
Mateva also noted that Bulgaria is experiencing a wave of standalone battery energy storage system (BESS) deployments and the hybridization of both existing and new solar assets with BESS, as developers look to deal with price cannibalization and declining solar capture rates.
“These developments are expected to reduce price volatility, improve system flexibility, and mitigate capture-price pressure for solar producers,” she explained. “As a result, industry expectations remain positive.”
Among the largest projects to be commissioned in Bulgaria last year was the first phase of the 315 MW/760 MWh Tenevo hybrid project, with a second phase scheduled for commissioning early this year, and the Selanovtsi hybrid project, a 59.8 MW solar plus 107.3 MWh storage site in the northwestern Vratsa region. Bulgaria also commissioned one of the EU's largest standalone BESS facilities last year, located adjacent to a 107 MW solar park.
Bulgaria’s C&I solar market is showing steady momentum, particularly among projects designed for self-consumption, Mateva added, with rising electricity costs incentivizing businesses to invest in on-site solar, often in combination with storage.
In contrast, Bulgaria’s residential solar sector remains underdeveloped in capacity terms. Mateva said interest among households exists but the market segment has been constrained by regulatory complexity and limited incentives.
She added that the residential sector would benefit from the full liberalization of Bulgaria’s electricity market, as currently household electricity prices remain regulated, accounting for roughly 40% of national electricity demand. “Full liberalization would stimulate demand-side participation and unlock the residential solar and storage market,” she explained.
Looking ahead, Mateva predicted Bulgaria is on course for a record year in solar deployment in 2026. “An estimated 2.5 GW of additional solar projects are either under construction or at an advanced stage of development and expected to start construction soon,” she said. “This pipeline suggests that most of this capacity will be commissioned by the end of 2026.”
Bulgaria’s storage pipeline is looking equally healthy, with 15 GWh expected to be commissioned by half way through the year, supported by the country’s National Recovery and Resilience Plan.
Mateva added that the most significant policy change last year was a sharp increase in eco-taxes and recycling fees for solar panels and batteries. She explained that these fees are currently five to ten times higher than in comparable EU countries, in turn artificially inflating PV and BESS project costs.
“Unless addressed, this issue risks becoming a major bottleneck for new PV and BESS procurement,” Mateva told pv magazine. “Resolving this will require action from the Ministry of Ecology to align recycling fees with real-world costs and EU norms, ensuring that Bulgaria’s strong solar momentum is not undermined by avoidable regulatory distortions.”
Bulgaria opened a new grant program late last year targeting micro, small and medium-sized enterprises looking to deploy PV systems and storage, with a particular focus on those located in the country’s coal regions. The call is set to close next month.
Bhutan’s Druk Green Power Corporation and India’s Carbon Resources Private Limited have agreed to collaborate on new solar and hydropower projects in Bhutan with capacities between 100 MW and 250 MW.
Bhutan’s leading renewables company Druk Green Power Corporation (DGPC) has signed a memorandum of understanding with Kolkata-based Carbon Resources Private Limited (CPRL) to jointly pursue renewable energy projects.
Under the terms of the partnership, DGPC and CPRL will collaborate on developing new solar and hydropower projects in Bhutan with capacities ranging between 100 MW and 250 MW.
DGPC will be responsible for sharing project information, past studies and regulatory frameworks to assist CRPL in undertaking required technical, commercial and financial assessments of potential projects.
Identified sites will then be developed through one or more special purpose vehicles incorporated in Bhutan as joint ventures between the two parties. The memorandum of understanding proposes a debt-equity financing structure of 70:30 between DGPC and CPRL.
The signing ceremony was attended by Bhutan’s Minister for Energy and Natural Resources, Lyonpo Gem Tshering, who said memorandums of understanding for more than 12 GW of generation capacity have been signed in the country to date.
Bhutan has a target of reaching 25 GW of installed generation capacity by 2040. A World Bank report published last June reported the country’s total generation capacity stood at 2.5 GW by the end of 2024, made up almost entirely of hydropower plants.
Bhutan’s first utility-scale solar plant, a 17.38 MW array located towards the centre of the country, was commissioned last July. A month later, a consortium consisting of local firm Rigsar Construction and India’s HILD Energy was awarded a contract to develop the 120 MW Jamjee solar project.
In December, DGPC opened a tender for the 120 MW Wobthang solar project. The project’s feasibility study and consultation meetings have since been completed, with DGPC planning to award the contract by June. The project is scheduled to begin construction this September and with the build expected to take around 18 months, is pencilled for operations during the first half of 2028.
Bhutan’s current national energy policy, published last year, aims to add 5 GW of solar capacity by 2040.
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Researchers in Iraq have developed biomimetic leaf vein–inspired fins for photovoltaic panels, with reticulate (RET) venation reducing panel temperature by 33.6 C and boosting efficiency by 18% using passive cooling. Their study combines 3D CFD simulations and electrical evaluations to optimize fin geometry, offering a sustainable alternative to conventional cooling methods.
A research group from Iraq’s Al-Furat Al-Awsat Technical University has numerically investigated the thermal and electrical performance of PV panels integrated with leaf vein–inspired fins. They have simulated four types of venation used by plants, namely pinnate venation (PIN), reticulate venation (RET), parallel venation along the vertical axis (PAR-I), and parallel venation along the horizontal axis (PAR-II).
“The key novelty of our research lies in introducing and systematically optimizing biomimetic leaf vein–inspired fin geometries as passive heat sinks for photovoltaic panels,” corresponding author Yasser A. Jebbar told pv magazine. “While conventional cooling approaches rely on simple straight fins, fluids, or active systems, our study is among the first to directly translate natural leaf venation patterns—particularly RET structures—into manufacturable backside fins specifically tailored for PV thermal and electrical performance.”
The team combined detailed 3D computational fluid dynamics (CFD) modeling with electrical efficiency analysis to identify geometries that maximize heat dissipation without additional energy input or water consumption. Next steps include experimental validation of the leaf vein fin designs under real outdoor conditions, particularly in hot climates.
The simulated PV panel consisted of five layers: glass, two ethylene-vinyl acetate (EVA) layers, a solar cell layer, and a Tedlar layer, with a copper heat sink and fins attached. All fin configurations were initially 0.002 m thick, 0.03 m high, and spaced 0.05 m apart. Panels measured 0.5 m × 0.5 m, with a surrounding air velocity of 1.5 m/s and incident irradiance of 1,000 W/m².
RET fins outperformed all other designs, reducing operating temperature by 33.6 C and increasing electrical efficiency from 12.0% to 14.19% —an 18 % relative improvement—compared to uncooled panels.
“This temperature reduction rivals, and in some cases exceeds, water-based or hybrid cooling methods, despite relying solely on passive air cooling,” Jebbar noted. The study also highlighted the significant impact of fin height, more than spacing or thickness, on cooling performance.
The team further optimized the RET fins, varying spacing from 0.02–0.07 m, height from 0.02–0.07 m, and thickness from 0.002–0.007 m. The optimal geometry—0.03 m spacing, 0.05 m height, and 0.006 m thickness—achieved the maximum 33.6 C temperature reduction and 18% efficiency gain.
UNSW researchers identified a new damp-heat degradation mechanism in TOPCon modules with laser-fired contacts, driven primarily by rear-side recombination and open-circuit voltage loss rather than series-resistance increase. The study highlights that magnesium in white EVA encapsulants accelerates degradation, guiding improved encapsulant and backsheet selection for more reliable modules in humid environments.
A research team from the University of New South Wales (UNSW) has identifed a new damp heat-induced degradation pathway in TOPCon modules fabricated with laser-assisted fired contacts.
“Unlike earlier studies dominated by series-resistance increase, the primary degradation driver here is a reduction in open-circuit voltage, linked to enhanced rear-side recombination,” the research's lead author, Bram Hoex, told pv magazine. “The new degradation mechanism emerged under extended damp-heat (DH) exposure.”
The scientists conducted their analysis on 182 mm × 182 mm TOPCon cells fabricated in 2024 with laser-assisted firing.
The TOPCon solar cells employed a boron-doped p⁺ emitter, along with a front-side passivation stack consisting of unintentionally grown silicon dioxide (SiOₓ), aluminium oxide (Al₂O₃), and hydrogenated silicon nitride (SiNₓ:H), capped with a screen-printed H-pattern silver (Ag) contact grid. On the rear side, the structure comprised a SiO₂/phosphorus-doped n⁺ polycrystalline silicon/SiNₓ:H stack, also contacted by a screen-printed H-pattern Ag grid.
The researchers encapsulated the cells with different bill of materials (BOMs): two types of ethylene vinyl acetate (EVA); two types of polyolefin elastomer (POE); and one type of EVA-POE-EVA (EPE). They also used commercial coated polyethylene terephthalate (PET) composite (CPC) backsheets.
“The mini modules were laminated at 153 C for 8 min under standard industrial lamination conditions,” the academics explained. “All modules underwent DH test at 85 C and 85% relative humidity (RH) in an ASLi climate chamber for up to 2,000 h to study humidity-induced failures.
Schematic of the TOPCon solar cells and modules
Image: UNSW, Solar Energy Materials and Solar Cells, CC BY 4.0
The tests showed that maximum power losses ranged from 6% to 16%, with the difference among these values depending strongly on the encapsulation BOM.
“The modules with POE on both sides were the most stable at around 8%, while those using white EVA on the rear side, especially in combination with EPE, showed the largest losses at around 16%,” said Hoex. “The primary driver of the degradation was a reduction in open-circuit voltage rather than the increased series resistance after DH testing, which diverges from previous findings that predominantly attributed DH-induced degradation to metallisation corrosion.”
The research team explained that higher levels of degradation were attributable to additives containing magnesium (Mg) in white EVA, which migrate under DH, hydrate, and create an alkaline micro-environment. “This alkaline chemistry corrodes the rear SiNx passivation layer, increases interfacial hydrogen concentration, induces local pinhole-like defects, and raises dark saturation current, ultimately reducing open-circuit voltage,” Hoex emphasized.
The scientists also explained that, although Mg in white EVA encapsulants and its role in acetic acid–induced degradation was previously reported, the effect of MgO on performance degradation in TOPCon modules was not explicitly studied.
“We hope this work helps refine encapsulant and BOM selection strategies for next-generation TOPCon modules, particularly for humid-climate deployment,” Hoex concluded. “It provides clear guidance for controlling Mg content in rear encapsulants and optimising rear-side passivation robustness. The mechanistic insights from this study have already informed upstream design changes, substantially reducing risk in commercial modules.”
China’s cumulative power-sector energy storage capacity reached 213.3 GW by the end of 2025, up 54% year on year, according to data from the China Energy Storage Alliance (CNESA). Pumped hydro accounted for 31.3% of the total, while “new-type” energy storage made up 67.9% – around 144.7 GW.
Based on CNESA DataLink 2025 annual energy storage dataset, presented at a press conference in Beijing on Jan. 22, a total of 66.43 GW/189.48 GWh of new-type energy storage systems were commissioned in 2025.
The added power and energy scales increased 52% and 73% year on year, respectively, which CNESA linked to a continued shift toward longer-duration configurations, it reported the average duration rising to 2.58 hours in 2025 (from 2.11 hours in 2021).
CNESA said the leading application scenario has shifted toward standalone energy storage, which accounted for 58%, while user-side storage fell to 8% and thermal-plus-storage frequency regulation to 1.4%; “renewables-paired storage” was described as stable.
Geographically, CNESA reported that the top 10 provinces each exceeded 5 GWh of newly commissioned capacity and together represented about 90% of additions. Inner Mongolia ranked first by both power and energy capacity, and Yunnan entered the top 10 for the first time.
Lithium iron phosphate (LFP) batteries continued to dominate, with CNESA reporting over 98% of new-type installed capacity. CNESA also noted emerging deployments of sodium-ion, vanadium flow, compressed air, gravity storage, and hybrid systems, separately citing a 40 MW/40 MWh grid-forming sodium-ion project in Wenshan, Yunnan as an example.
On procurement, CNESA reported 690 energy storage system tenders (excluding centralized/framework procurement), down 10.4%, while EPC tenders rose to 1,536, up 4.5%. Winning bid volumes (excluding centralized/framework procurement) reached 121.5 GWh for systems and 206.3 GWh for EPC.
CNESA’s tender-price analysis for LFP systems (excluding user-side applications) reported a 2025 winning bid price range of CNY 391.14/kWh ($55/kWh) to CNY 913.00/kWh ($128/kWh). For EPC (excluding user-side), CNESA reported average winning bid prices of CNY 1,043.82/kWh ($146/kWh) for 2-hour projects and CNY 935.40/kWh ($131/kWh) for 4-hour projects.
CNESA also launched a policy “map” for standalone storage market mechanisms covering 21 provinces.
A report from LevelTen Energy finds solar PPA prices in North America rose 3.2% in Q4 2025, marking a nearly 9% year-over-year increase as developers and buyers navigate a complex “post-OBBBA” regulatory environment.
Renewable energy power purchase agreement (PPA) prices continued their upward trajectory in the final quarter of 2025, driven by persistent policy headwinds and a shifting tax credit landscape.
According to the Q4 2025 PPA Price Index from marketplace operator LevelTen Energy, solar P25 prices rose by 3.2% following a 4% increase in the third quarter.
While solar costs climbed, wind PPA prices saw a slight dip, declining 1%. However, on an annual basis, both technologies have seen prices surge by nearly 9% compared to the same period last year.
Post-OBBBA
The market is currently adjusting to the “One Big Beautiful Bill Act” (OBBBA), which introduced tax credit cuts. LevelTen noted the second half of 2025 was defined by “ruthless” prioritization as firms scrambled to safe-harbor projects.
Despite these challenges, a November survey of developers representing over 230 GW of capacity found that more than 75% of projects slated to go online before 2029 expect to successfully retain access to tax credits.
This clarity has allowed some developers to dial in pricing by removing risk premiums that had previously accounted for OBBBA-related uncertainties, said the report.
Regional pricing
The report highlights significant price disparity across North American ISOs. For solar, P25 prices reached as high as $115 per MWh in ISO-NE and $81.03/MWh in PJM, while ERCOT remained the most competitive at $49 per MWh.
ISO Market
Solar P25 Price ($/MWh)
ISO-NE
$115.00
PJM
$81.03
MISO
$64.95
CAISO
$62.00
ERCOT
$49.00
In the wind sector, ERCOT has seen a massive 19% year-over-year price hike, fueled by an ongoing boom in data center development and a premium on available capacity.
Buyer headwinds
LevelTen pointed to several factors that could continue to apply upward pressure on prices:
Tariff uncertainties: Ongoing Section 232 investigation tariffs are adding direct development costs.
Permitting hurdles: “Harsh” new federal permitting procedures have stalled substantial amounts of development nationwide.
FEOC: The industry is still awaiting guidance on Foreign Entity of Concern (FEOC) rules, which are expected to add compliance costs and further complicate tax credit qualification.
Corporate strategy
Many corporate buyers are now pausing or adjusting their procurement strategies due to proposed updates to the Greenhouse Gas Protocol (GHGP) Scope 2 standards, said the report. The updates, expected to be finalized in 2027, may introduce more stringent accounting for hourly matching and physical deliverability.
“The current uncertainty has caused some buyers… to adjust or even delay their procurement strategies,” the report said.
LevelTen encourages industry players to weigh in on the proposal, as 97% of companies tracking emissions currently utilize the GHGP.
As buyers and sellers work to establish a “pricing equilibrium,” the report said in markets where contract values are challenging, sellers may need to find more transactable pricing levels to get deals done.
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In Short : Around 740 households in Tripura are earning additional income by selling surplus solar power to the electricity grid. The initiative highlights the success of rooftop solar adoption and net metering policies, enabling consumers to become energy producers, reduce electricity bills, and contribute to clean energy generation and decentralized power systems.
In Detail : Tripura has emerged as a promising example of decentralized renewable energy adoption, with around 740 households now earning income by selling excess solar power to the electricity grid. This development reflects the growing acceptance of rooftop solar systems and the effectiveness of supportive policies that encourage consumer participation in clean energy generation.
The households have installed rooftop solar photovoltaic systems under government-supported programs aimed at promoting renewable energy at the consumer level. These systems allow households to generate electricity for their own use and export surplus power to the grid, transforming consumers into “prosumers” within the energy ecosystem.
Net metering plays a central role in enabling this model. Through net metering mechanisms, electricity exported to the grid is measured and credited against the household’s power consumption, allowing users to receive financial compensation or bill reductions based on the amount of energy they supply.
This arrangement provides direct economic benefits to households by reducing monthly electricity expenses and creating a supplementary income stream. Over time, the savings and earnings can help recover the initial investment in solar installations, making rooftop solar a financially attractive option for residential consumers.
From a system perspective, decentralized rooftop solar reduces pressure on centralized power plants and transmission networks. Local generation helps lower peak demand, reduces transmission losses, and improves overall grid efficiency, especially in geographically dispersed or remote regions.
The initiative also contributes to environmental sustainability by increasing the share of clean energy in the state’s power mix. Each rooftop system reduces reliance on fossil fuel-based electricity, leading to lower carbon emissions and improved air quality at the local level.
The success of these households demonstrates the importance of policy support, financial incentives, and public awareness in driving renewable adoption. Subsidies, simplified approval processes, and technical assistance have played a crucial role in encouraging residents to invest in solar power.
Beyond individual benefits, the program supports broader socio-economic development. It promotes energy self-reliance, encourages community-level participation in clean energy, and builds local capacity in solar installation, maintenance, and technical services.
Overall, the experience of 740 households in Tripura earning income from rooftop solar power highlights the transformative potential of decentralized renewable energy. It shows how clean energy can simultaneously deliver economic empowerment, energy security, and environmental sustainability at the grassroots level.
Wuxi DK Electronic Materials is pursuing two patent infringement cases against domestic competitors, seeking injunctions, equipment destruction, and combined damages of CNY 400 million ($57.5 million).
Wuxi DK Electronic Materials has filed two patent infringement lawsuits with the Jiangsu High People’s Court against Jiangsu Riyu Photovoltaic New Materials and Suzhou Jinyin New Materials Technology , seeking CNY 200 million in damages and related legal costs in each case.
The company said both filings have been formally accepted and registered by the court, although hearing dates have not yet been scheduled.
The lawsuits concern two Chinese invention patents, ZL201180032359.1 and ZL201180032701.8, covering thick-film conductive paste formulations for semiconductor devices, including solar cells. DKEM said the patents are held by its subsidiary Solamet Electronic Materials and relate to lead-tellurium-lithium and oxide-based paste technologies.
DKEM is seeking injunctions to halt the manufacture, sale, and offering for sale of the allegedly infringing pastes. The company is also requesting the destruction of dedicated production equipment and molds, and compensation for economic losses, enforcement costs, and related expenses.
The patents trace back to the intellectual property portfolio of DuPont’s former Solamet photovoltaic paste business, acquired by another entity in 2021 for $190 million. DKEM later consolidated control of the Solamet assets and associated intellectual property.
Suzhou Jinyin is described in Chinese financial reporting as a leading supplier of front-side silver paste for solar cells, ranking third globally by market share. Founded in 2011, it was later acquired by listed electronics firm Suzhou Good-Ark Electronics. Jiangsu Riyu is a fast-growing paste supplier that filed a Hong Kong listing application in 2025, with plans to expand into n-type and back-contact paste products.
This follows earlier high-value patent actions by DKEM. In 2025, its subsidiary filed a suit against Zhejiang Guangda Electronic Technology seeking similar remedies. A Solamet-linked entity also pursued related claims against Changzhou Juhe New Materials in 2021, with domestic and overseas disputes reportedly settled in August 2022.
Separately, DKEM flagged earnings pressure, forecasting a net loss of CNY 200 million to CNY 300 million for 2025, primarily linked to non-operating factors, according to Chinese financial media.
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