Extending the lifetime of lithium-ion batteries beyond their end-of-life in electric mobility applications is a sustainable pathway to reduce environmental impact and improve resource utilization. Batteries retired from electric ferry operations typically retain substantial residual capacity compared with those from ground electric vehicles, mainly due to their comparatively lower dynamic loading profiles. This makes them promising candidates for second-life battery energy storage system (BESS) applications. However, aging-induced degradation and uncertainties in operational behaviour resulting from their first life require carefully designed charging strategies to ensure safe, efficient, and long-term operation. This paper presents a preliminary investigation towards identifying suitable charging strategies for second-life batteries. Different charging strategies are evaluated for second-life BESSs utilizing retired electric ferry cells, with particular emphasis on extending battery lifetime and supporting sustainable operation. These include constant current–constant voltage (CC–CV), multistage constant current (MCC), constant power (CP), and boost charging (BC). Their impacts on battery lifetime are assessed in terms of capacity degradation, charging duration, impedance evolution, and cell surface temperature trends. The results demonstrate that cells cycled using the BC protocol exhibit the highest degradation, whereas the MCC protocol results in the lowest degradation, but at the expense of increased charging time. In comparison, the CC–CV and CP strategies provide a favourable compromise between charging duration and degradation. These findings highlight charging strategy selection as a critical factor for extending the service life and supporting the sustainable deployment of second-life batteries in stationary energy storage applications.

The increasing penetration of renewable and inverter-based resources is reducing operating margins and increasing the complexity of power-system security assessment. This paper introduces a geometry-conditioned entropy framework for assessing operational fragility under the DC load-flow approximation. The feasible operating region is represented as a convex polytope in reduced injection space, enabling the definition of direction-independent distances to feasibility boundaries and associated local robustness margins. The framework combines a geometric distance-to-infeasibility measure with three complementary entropy-based indicators: flow entropy, redispatch-sensitivity entropy derived from PTDF coefficients, and a Distance-Weighted Redispatch Diversity Index (DWRDI) that incorporates proximity to feasibility boundaries. Application to the IEEE-39 bus system shows that shrinking feasibility margins can be detected before any constraint activation occurs. As feasibility margins contract, system behaviour becomes progressively governed by a decreasing number of feasibility facets, eventually a single limiting constraint. The proposed framework provides a geometry-based early-warning perspective on declining operational flexibility and the evolution of constraint dependence while all operating limits remain satisfied.

Europe’s energy transition is accelerating while grid expansion remains constrained. Growth in electric vehicles, charging infrastructure, electrified heating and data centers is increasing demand and peak loads, making flexibility increasingly important. Under the AFIR framework, EN ISO 15118-20 becomes applicable to newly installed or renovated public charging infrastructure from January 2027, potentially enabling services such as Plug & Charge, smart charging and bidirectional power transfer.

The transition from earlier communication standards to ISO 15118-20 coincides with evolving security requirements, certificate handling, bidirectional charging functions and new conformance test specifications. Legacy and new protocol generations must also coexist, increasing implementation and interoperability risk only months before the regulatory transition.

This paper presents a three-stage validation methodology: (1) early communication-layer validation before complete hardware integration; (2) system-level EV and EVSE testing under controlled AC and DC power conditions; and (3) automated in-house pre-certification using standards-derived conformance and regression testing.

A particular focus is the test counterpart itself. Development teams often create home-grown EV or EVSE emulators, effectively maintaining a second implementation of the evolving standard. This adds development and regression effort and may create false confidence when the device under test and emulator share code, libraries or interpretations of the specification. The methodology therefore combines controlled emulation with independent conformance testing and cross-checking.

The proposed framework enables earlier defect isolation, reproducible verification of communication and power behaviour, and measurable assessment of correction effort, counterpart maintenance, regression coverage and external rework. With the ISO 15118-20 transition only months away, staged and automated validation provides a practical route from protocol implementation to interoperability and certification readiness.

Planning large-scale deployment of offshore wind requires coordinated assessment of future electricity demand, transmission infrastructure, electricity market development, and system operations. These elements are often evaluated independently, resulting in inconsistent assumptions and suboptimal infrastructure planning under uncertain future demand. This paper presents an integrated planning framework developed through the Atlantic Canada Offshore Wind Grid Integration and Transmission Study. The framework links electricity market modelling, high-resolution offshore wind resource assessment, geospatial analyses, transmission expansion and electricity system modelling within a single iterative workflow. Future electricity demand scenarios, including domestic electrification, electricity exports, and clean fuels production, are used to define offshore wind deployment pathways, which are subsequently evaluated for transmission requirements and operational performance. Application of the framework demonstrates that Atlantic Canada's technical offshore wind resource substantially exceeds projected deployment requirements. Instead, future deployment is primarily influenced by export market demand, transmission capacity, project economics, and regional coordination rather than resource availability. The study identifies transmission investment pathways to support a range of offshore wind development scenarios and demonstrates the value of integrated, demand-driven planning for evaluating offshore wind deployment under demand uncertainty. While developed for Atlantic Canada, the methodology is transferable to other emerging offshore wind jurisdictions.

• To avoid disconnection from the grid, data centers must meet certain requirements. These include the ability to ride through temporary voltage changes (fault ride-through, FRT) and robustness against large frequency changes (rate of change of frequency, RoCoF).
• After a grid fault, data centers must demonstrate a rapid (and ramped) power recovery to grid parallel operation as soon as the grid voltage has reached the regular operating limits.

• Therefore, load volatility must be limited in the short term to ensure system stability and the undisturbed operation of parallel systems.
• Data centers need to provide or demand reactive power within their technological capabilities to compensate for voltage changes due to changes in operational load.

• Inter-area and local oscillations of generator groups,
• Sub-synchronous interactions with neighboring power plants and converters (SSTI, SSCI),
• High-frequency interactions.

Battery-buffered Fast-charging systems (BBFCSs) enable high-power Electric Vehicle (EV) charging at sites where the grid

With the increasing deployment of renewable energy sources and the gradual phase-out of conventional power plants, transmission system operators increasingly source ancillary services from distributed and renewable generators. Market-based procurement mechanisms for reactive power create new revenue opportunities for operators of photovoltaic (PV) power plants and wind power plants. However, reactive power provision induces additional losses along the power conversion chain, directly affecting the economic viability of market participation. This study presents field measurements from a 650 MWp PV power plant directly connected to the 380 kV transmission grid. During the analysed period, 605 MWp of DC capacity and 415 MVA of inverter capacity were operational. Power was measured at four levels within the plant, enabling a detailed analysis of losses from the DC side of the inverters, through the medium- and high-voltage transformers, up to the point of common coupling. The measurements quantify the loss chain and the incremental losses associated with reactive power provision over a wide range of operating points, including reactive power provision at night. At a feed-in of approximately 400 MW, the total losses between the inverter DC terminals and the point of common coupling were approximately 13 MW. Within the observed underexcited operating range, the estimated incremental losses were approximately 0.7 MW per 100 Mvar during normal feed-in and 1.4 MW per 100 Mvar during night-time reactive-power operation. The results are compared with a simulation model of the plant. The results provide a field-data benchmark for validating loss-estimation models for utility-scale PV power plants.

Electric mobility offers increasing flexibility potential for electrical energy systems, particularly through controllable charging processes. This paper quantifies the cost-reduction potential of optimized charging for the specific case of employee charging at a company site with 30 charging points, using historical charging data spanning 1.25 years. The analysis focuses on behind-the-meter use cases, including dynamic electricity tariff optimization, photovoltaic self-consumption optimization, peak shaving, and their combined application.

The results show that optimized charging can significantly reduce charging-related costs compared to uncontrolled charging. Individual use cases already provide measurable savings, while combined optimization achieves cost reductions of up to 40%. In the investigated employee-charging case, bidirectional charging provides only limited additional benefits due to short dwell times and grid fee structures. However, bidirectional charging has the capacity to yield further value when integrated with additional local loads, such as those from buildings or production sites, and may offer broader potential in other application contexts.

The provision of inertia through grid-forming capabilities of generation plants and battery energy storage systems is a key element in ensuring system stability. In addition to the established German certification framework for grid-code compliance, qualified plant reports are increasingly required for grid connections to the public extra-high-voltage network, particularly in the context of the rapid expansion of battery storage grid connections in Germany. Within these assessment reports, evidence must be provided regarding several grid-forming related electrical characteristics.

The required evidence must be demonstrated using detailed RMS and/or EMT models of the respective plants, whose components are to be modelled over a frequency range of at least 3 Hz to 2.5 kHz. For this newly defined verification process, this paper provides an experience report based on early grid connection processes and illustrates selected verification steps using a simplified fictitious plant model. In doing so, lessons learned regarding the emerging need for case-specific coordination among the project stakeholders are shared, and the practical applicability of the described guidelines is examined.

Low-frequency electromechanical oscillations (0.1–2.5 Hz) threaten the stability of interconnected large power systems. Power system stabilizers (PSS) are the most cost-effective solution for enhancing damping via generator excitation system. Since the 1960s, numerous PSS design methods have been proposed, ranging from classical phase compensation to modern intelligent algorithms [1-3]. This paper provides a comprehensive review of these methods, systematically analyzing their principles, advantages, limitations, and applicability in modern power systems.

The future Nordic power system is expected to have reduced system rotational energy and challenging frequency stability because of an increased share of inverter-based renewable generation. This paper develops a rotational energy estimation model by estimating synchronised generation capacity from generation output using technology-specific loading factors and validates against 2022 measurements. The results show that the model has a mean relative error of −1.3% and a standard deviation of 7.2%. The model is then applied to a cost-optimal decarbonised 2050 Nordic scenario to investigate future system rotational energy. The results indicate that the future rotational energy ranges from 19.8 to 293.4 GWs, with values below 120 GWs for 22.8% of all investigated operating conditions. The analysis further shows that synchronised hydropower upward reserves are below the frequency containment reserve for disturbances (FCR-D) up requirement (1450 MW) for 73.7% of the time. Dynamic frequency analysis of a selected critical operating point shows that the system frequency nadir may reach as low as 47.5 Hz when hydropower is the only FCR-D provider. This will trigger under-frequency load shedding, highlighting the importance of considering frequency stability criteria when developing cost-optimal capacity expansion energy system models.

This study analyzes the impact of the European energy transition on system adequacy and cross-border electricity exchange under high shares of variable renewable energy sources. The focus is on Germany and its neighboring electricity markets under the assumption that all countries meet their 2030 National Energy and Climate Plan (NECP) expansion targets for wind and photovoltaic (PV) capacities. Particular attention is given to the simultaneity of extreme meteorological conditions, namely extended low-generation periods (Dark Doldrums) and high-generation surplus events (Bright Breezes).

This paper investigates the economic incentive of German onshore wind turbines to curtail generation during negative wholesale electricity prices by reconstructing the applicable regulatory framework for the installed wind fleet. Negative electricity prices are becoming increasingly relevant in power systems with high shares of variable renewable generation. Whether wind power operators have an economic incentive to curtail generation during such periods depends strongly on the applicable remuneration and market participation regime. Based on turbine-level data from the German Federal Network Agency and the commissioning date of each turbine, the operational onshore wind capacity is classified into three remuneration groups: post-support turbines, turbines with voluntary direct marketing, and turbines subject to mandatory direct marketing. The resulting curtailment thresholds are derived from the interaction between wholesale electricity prices, reference remuneration values, and monthly wind market values. By the end of 2025, the analyzed German onshore wind fleet comprises approximately 67.7 GW of net installed capacity, of which 12.49 GW are classified as post-support capacity, 22.45 GW as capacity with voluntary direct marketing, and 32.77 GW as capacity subject to mandatory direct marketing. The analysis shows that the economic response to negative prices differs substantially across these regulatory groups. Using monthly wind market values for 2026, most of the capacity has a direct incentive to curtail once wholesale prices become negative, whereas in periods with lower market values, market premiums can shift the curtailment threshold to significantly more negative price levels. The results demonstrate that regulatory remuneration schemes are a key determinant of the price responsiveness of the German onshore wind fleet and should therefore be explicitly considered when assessing the effects of negative electricity prices on renewable generation.

This work proposes an energy management system for a hybrid power plant comprising a wind power plant and battery energy storage system. The proposed optimizer determines power references while accounting for operational strategies, turbine structural loading, and battery degradation. It maximizes expected profit under varying wind conditions and electricity price signals, while explicitly capturing additional turbine loading associated with start-up and shutdown events. A case study demonstrates a significant increase in expected profit compared with a conventional revenue-maximizing strategy, while maintaining lower component loading and associated costs. A parametric study comparing different price signals illustrates the revenue–cost trade-off and demonstrates the response of the optimizer to different market conditions.

• Development of an enhanced predictive grid-forming algorithm that combines the features of a feedback architecture with the inherent predictive capabilities of model predictive control. Compared to more traditional approaches, this scheme enables the minimization of undesired resonance conditions under long transmission cables, without the need for dedicated damping controllers—which are often difficult to design and tune under real operating conditions.
• Application of the proposed strategy to the emerging direct AC-AC power conversion technology for cost-effective interconnection of renewable-based offshore generation, and investigation of the inherent transient stability improvements provided by this solution.

The rapid expansion of inverter-based resources poses growing challenges regarding harmonic resonances and grid stability. This paper presents and evaluates a measurement-based modelling and simulation workflow that enables impedance-based stability assessment at the plant level to identify critical resonance conditions. For this purpose, differential impedance spectroscopy was used to characterise inverters and plant components in a laboratory setting. These measurements yielded frequency-dependent Thévenin equivalents and enabled the parametrisation of generic library models. In combination with the documented plant topology and equipment data from operating PV parks, plant models were derived and validated against field measurements, showing good agreement in the fundamental characteristics of the simulated and measured plant impedances. Furthermore, resonance stability was assessed for various scenarios at selected points within the plant using the impedance-based stability criterion. The results demonstrate that measured unit impedances, combined with plant topology and component data, can be used to estimate plant impedances and assess resonance stability already during the planning phase. This approach can support the design and certification of PV plants by identifying potential critical interactions before commissioning.

The development of converter-based renewable generation (CRG) has fundamentally changed the power system dynamics. As CRG replaced conventional generations, the system oscillation modes changed. Although CRG can provide voltage support, the reduction in the inherent damping and inertia of synchronous generators results in decreased damping of low-frequency electromechanical oscillations.

Electric vehicle (EV) charging synchronization causes voltage violations in low-voltage (LV) distribution grids. To resolve these operational limits, this paper proposes a communication-free, decentralized adaptive voltage-power (V-P) charging strategy that combines grid stability, spatial fairness, and end-user economic optimization. We validate the proposed architecture through Monte Carlo simulations on the IEEE LV test feeder, integrating empirical residential EV charging data from France to capture stochastic real-world demand. We benchmark the algorithm against uncontrolled demand, traditional voltage droop, and price-optimized charging. Results demonstrate that the adaptive V-P controller matches the EN50160 compliance of traditional droop control (0.0% of simulation runs resulting in voltage violations) while significantly improving spatial equity across the feeder. Economically, the strategy achieves the same average charging price (0.11 €/kWh) as price-optimized scheduling, outperforming both droop and uncontrolled baselines.

As large-scale hydrogen import becomes increasingly important for low-carbon energy systems, efficient unloading of liquid hydrogen at receiving terminals is a key operational issue. Conventional unloading commonly relies on submerged cryogenic pumps, but these systems can increase maintenance burden and operating cost because of reliability issues, cavitation risk, and difficult maintenance inside cargo tanks. This study evaluates a compressor-assisted unloading concept in which make-up boil-off gas from the receiving terminal is compressed and injected into the carrier tank to transfer liquid hydrogen without a submerged pump.

The use of wind power energy has gradually increased as we pay attention to mitigate the CO2 emission and climate change. South Korea government intends that the electricity production by wind power energy would be 20% in 2030, which may lead more offshore wind farms. For economical design of offshore wind farm, we need credible geotechnical parameters. Site investigation and lab test should provide appropriate geotechnical parameters. For laboratory tests, undisturbed samples are collected for geotechnical tests. We should determine whether the undisturbed sample is applicable to provide credible geotechnical parameters by designated tests. Sample disturbance can be quantified by non-destructive and large-deformation methods. This study shows a potential method of elastic wave velocity measurements to validate and quantify undisturbed sample quality on shipboard.

In recent years, the decarbonization of electricity generation has driven a rapid integration of renewable energy sources connected to the grid through power converters. In this context, transient stability studies have gained critical importance, as ensuring the resilience of power systems with high penetration of inverter-based resources is essential to prevent large-scale blackouts, such as the one experienced in the Iberian Peninsula in April 2025. Among renewable technologies, wind power has emerged as a backbone of the energy transition, with global installed capacity growing by 225.5% over the last decade, reaching an estimated 1.32 TW by the end of 2025.

Large demand facilities such as data centres, are being connected to the Finnish power system. These new loads have a significant impact on the stability and performance of the power system. Fingrid, the TSO of Finland, has published a draft of an updated grid code for demand facilities in 2026 that introduces several new requirements set for loads exceeding 30 MW. The new requirements are based on comprehensive studies in which system needs related to frequency stability, voltage stability and secure interconnection operations were assessed. Two critical technical requirements for maintaining frequency and voltage stability are Low Voltage Ride Through (LVRT) and Post-Fault Active Power Recovery (PFAPR). In addition to this, special attention must be paid to load types such as AI training clusters, which may excite inter-area oscillation modes. This paper outlines the key findings from the system studies, presents the main technical requirements for demand facilities, and briefly describes the compliance process.

The electrification of transport creates rising and increasingly simultaneous energy demands for large vehicle fleets. Bidirectional charging turns these vehicles into flexible resources that can serve several markets at once. For energy-intensive sites with their own grid level, such as Frankfurt Airport, this creates substantial potential. No transferable concept yet combines spatial charging infrastructure, simultaneous market participation and multi-day planning for a large commercial fleet under real operating conditions. This paper develops such a concept within the ReSkaLa@FRA living lab, using operational data from Frankfurt Airport. It identifies three use cases, spot arbitrage, self-consumption optimisation and balancing services, and unites them in a rolling-horizon optimisation architecture. Its central finding is that the difficulty of multi-use operation lies not in the battery but in four couplings: temporal, physical, spatial and fiscal. A naive formulation overlooks all four. The result is a practice-oriented framework that provides a scientific contribution to V2G research and a directly applicable foundation for integrating large fleets as flexible resources in industrial energy management.

Grid codes increasingly require wind power plants to provide damping for inter-area oscillations. A key performance indicator is the phase shift between grid voltage and the reactive power at point of common coupling, known as the POD-Q response. However, the effective damping contribution is significantly compromised by communication delays between the power plant controller and individual wind turbines, as well as by turbine-level response times. This paper analyzes the impact of communication delays, controller processing delays, and converter response delays on POD-Q performance. Based on this analysis, a WPP communication architecture, a plant-level control strategy, and a practical parameter tuning scheme are proposed. The tuning scheme explicitly compensates for measured round-trip delays using a phase-lead filter. To test and verify the optimized POD-Q function, a hardware-in-the-loop testing platform is developed, integrating the plant controller, communication system emulation, and converter controls. This platform enables comprehensive validation of communication delays, and power oscillation damping capability. A GOOSE-based fast communication system and a plant-level POD control system are deployed in an Italian wind farm. Field tuning tests demonstrate that after optimization, the POD-Q response meets the required open-loop phase shift. For example, at 0.1 Hz, the measured phase shift that reactive power lagging voltage is -150°, which lies well within the required range of -90° to -180° for positive damping under the negative-feedback convention. These results confirm that the optimized POD-Q response complies with the phase shift requirements of the Italian Terna grid code.

The electrification of the transport and heating sector is increasing load levels and investment requirements in distribution grids, creating a growing need for automated and forward-looking expansion planning. This paper presents a practical framework for automated multi-period grid expansion planning and applies it to a real medium-voltage grid area. The planning problem combines network models, load forecasts, technical constraints, reinforcement measures and a hierarchical objective function. A Genetic Algorithm generates candidate expansion paths, while AC load flow calculations assess normal-operation and N−1 security across multiple planning years. The influence of algorithm parameterization, forecast assumptions and available measure libraries on solution quality, computational effort and investment strategies is investigated systematically. The results confirm the suitability of Genetic Algorithms for this application, showing that the parameterization substantially affects both solution quality and runtime. Although the Ambitious Scenario for electrification increases overall investments, many reinforced assets remain consistent with the Reference Scenario, while investment timing changes more strongly. Restricting topology modifying measures generally raises costs, whereas limiting cable cross-sections reduces the modelled network investment costs by increasing the use of existing infrastructure. The findings highlight that meaningful automated planning requires current network models, representative forecasts, realistic measures and a comprehensive cost model.

This paper investigates forecasting and market commitment strategies for photovoltaic plants coupled with battery energy storage systems (flexible PV plants). A grey-box forecasting framework is developed to predict firm PV generation, residual variable output, and battery state of charge by combining machine learning based PV forecast with a deterministic power plant controller model. A set of key performance indicators is defined to quantify supply reliability and solar-induced system flexibility. These KPIs are used to compare unconstrained PV generation with different firm and near-firm market commitments. The forecasting framework is applied both to correct/optimize baseload commitment (firm strategy) and to predict residual variable components of flexible PV generation, enabling simultaneous firm and residual generation trading (generation splitting strategy). The methodology is tested using measurements from a 662 kWp PV plant in Bolzano, Italy. Results show that reliable 24/365 baseload supply has no impact on system flexibility but, at the current storage costs, remains techno-economically unfeasible. In contrast, forecast-based near-firm commitments provide a more effective trade-off between production costs, cost-optimal firm supply and reduction of solar-induced system flexibility. Generation splitting further improves competitiveness by allowing residual variable output to participate in the day-ahead market, lowering production costs while preserving system benefits.

As part of the German research project SkIES - Scalable Integration of Energy Sharing, this study addresses questions on how the flexibility provided by a shared battery in an energy community can be coordinated and examines its effects on the integration of local renewables, cost, and optimal battery sizing. The study uses a simulation framework drawing on a pool of synthetic and heterogeneous load profiles, representing household with and without rooftop PV and behind-the-meter storage, alongside shared PV and wind assets. Three scenarios representing increasing coordination are introduced, a rule-based baseline, pooling of residual household flexibility after individual optimisation, and full centralised dispatch minimising residual grid demand. Each is evaluated under flat and dynamic spot-price tariffs, with battery capacity systematically varied. Comparing costs, curtailment, and self-sufficiency by source reveals that coordination primarily changes which asset supplies flexibility. Central optimisation reallocates household batteries' discharge from directly covering their own owner's load to a pool-facing role, curtails renewable generation at roughly a third of the baseline's rate, and lowers cost, though substantial cost reductions are realised only when coordination is paired with a dynamic tariff. The cost-optimal battery size is set almost entirely by the tariff and barely shifts with coordination mechanism or community size.

The increasing penetration of power-electronic-interfaced devices (PEIDs) is introducing new oscillatory phenomena that extend beyond the frequency range traditionally monitored using phasor-based techniques. These oscillations may exhibit low amplitudes, time-varying characteristics, and intermittent behaviour, making reliable detection challenging. This paper presents a wide-band oscillation detection methodology based directly on waveform measurements. The proposed approach combines short-time Fourier transform (STFT) analysis for spectral estimation, quasi-peak filtering inspired by CISPR 16 measurement techniques, and frequency-dependent trigger logic. By evaluating both the magnitude and persistence of spectral components, the method distinguishes sustained oscillatory behaviour from transient disturbances, harmonics, and measurement noise.

The methodology is first demonstrated using synthetic waveform data containing sustained oscillations, transients, sags, impulse disturbances, and additive noise. Results show that weak oscillatory components can be reliably detected while maintaining robustness against short-duration events. The method is subsequently applied to measurements from a historical HVDC-related oscillation event, where it successfully identifies oscillatory behaviour in the presence of significant harmonic content. Finally, implementation aspects related to waveform measurement units, selective waveform storage, and wide-area monitoring applications are discussed. The results demonstrate that waveform-based monitoring can provide a practical approach for detecting oscillations in a converter-dominated power system.

The decarbonisation of the energy and transport sectors requires solutions that increase renewable energy utilisation while providing flexibility to power systems. Workplace charging is particularly well suited for this purpose because electric vehicles (EVs) are typically connected for longer than needed to complete charging. This paper investigates the charging behaviour and flexibility potential at two workplace charging sites located on a university research campus and a high school campus in Denmark. Using 21 months of field data from each site, we analysed the arrival and departure time, charged energy, charging duration, and post-charging idle time. These observations are used to quantify power-, energy-, and time-based flexibility and to assess the seasonal alignment between charging demand and on-site photovoltaic (PV) generation. The results show that both sites remain well below their grid connection limits: over the study period, the average power drawn while at least one EV is charging stays below 45% of capacity, and the average daily peak power reaches around 65% of the grid capacity. In addition, local PV generation meets approximately 55\% of charging demand during summer but less than 15% in winter. These findings provide practical guidance for workplace smart charging and its integration with local renewable energy systems.

Europe’s energy transition is entering a new phase in which optimizing existing renewable assets becomes as important as deploying new capacity. During the first large-scale expansion of wind and solar power in the 2000s and 2010s, a substantial renewable fleet was installed across Europe. Today, a significant share of this fleet is reaching technical maturity, creating both challenges and opportunities for the next stage of decarbonization.

The increasing integration of wind power requires advanced control strategies to maintain stable and reliable grid operation during disturbances. Grid-forming inverters can provide voltage support and improve system strength, but conventional control structures do interact with wind turbine mechanical dynamics and cause oscillations which could further lead to cause mechanical fatigue to the turbine . To address this, the VSM-Split concept is applied, separating the virtual synchronous machine (VSM) and fast voltage control loop from the converter current control loops. The VSM and voltage controller are implemented at the point

Due to the expansion of renewable energies in the electrical grid, the number of inverter-based resources (IBR) is increasing. This leads to inverter-grid interactions which can be critical for the system stability of the grid. It can form resonance circuits together with IBRs at certain frequencies, which affects system stability. To investigate whether a resonance circuit exists at a frequency inside a system without knowledge of the detailed inverter structure, the frequency dependent impedance of a power plant as well as of the grid is required. In this paper, the frequency dependent impedances of two inverter control types are presented: A grid following inverter control and a grid forming inverter control realized as a droop control, which are each parameterized as a photovoltaic or type-4 wind power plant EMT average model. For each control type and parameterization, the frequency dependent impedance is calculated and compared for a variation of parameters and operating points. The characteristic changes due to parameter variations in the frequency dependent impedances of grid forming and grid following control are explained and compared for each type of power plant. The inverter models with a simplified primary side are also each compared to power plant models with a detailed primary side to investigate how complex power plant modelling must be to generate accurate frequency impedances.

The replacement of synchronous generation by inverter-interfaced distributed energy resources (DERs) lowers system inertia and

Offshore wind power has been attracting significant attention toward achieving carbon neutrality by 2050 in Japan. While offshore wind farms (OWFs) allow for large-scale integration, they are often located far from load centers. high-voltage DC transmission (HVDC) systems using submarine cables are therefore expected to be a viable solution for long-distance, high-power transmission because they do not generate reactive power. Multi-terminal HVDC systems are being considered as a means to efficiently distribute generated power to multiple load centers, and the effectiveness of power sharing between AC grids interconnected via the HVDC system has also been demonstrated.

Towards a sustainable society, achieving carbon neutrality is globally required, and the expansion of renewable energy sources (RES) and the proliferation of battery electric vehicles (BEVs) are expected to accelerate further. However, RES pose challenges due to their instability and significant fluctuations in power output caused by weather conditions. In this context, it is effective to establish microgrids (MGs) at a regional level and ensure power supply stability by utilizing storage batteries to balance demand and RES supply within the grid.

Achieving carbon neutrality requires wider adoption of renewable energy (RE), electric vehicles (EVs), and reused vehicle batteries. Community microgrids (MGs) can support local energy management by balancing supply and demand and improving the utilisation of variable renewable generation. This paper evaluates the long-term economic performance of a community MG integrating photovoltaic (PV) generation, biogas power generation (BG), reused nickel–metal hydride (Ni-MH) batteries, reused lithium-ion batteries (LIBs), and municipal fleet EVs through a V2X system. Reused Ni-MH batteries are used for PV output smoothing, whereas connected EVs and reused LIBs are used for power balancing.

Three models are compared: a normal charging model, a planned-purchase V2X model, and a zero-purchase V2X model. In the normal charging model, EVs are charged without V2X discharging, and BG output is set on the basis of minimum demand. The planned-purchase V2X model uses a 59.4 kWh reused LIB and coordinates BG output adjustment with planned grid power purchase to mitigate reverse power flow during low weekend demand. BG output is determined from the cumulative deviation of weekend residual demand, while planned power purchase is regulated according to the average state of charge (SOC) of connected storage devices. The zero-purchase V2X model uses a 574 kWh reused LIB, with BG output set on the basis of weekly average net demand to eliminate grid power purchases.

Numerical simulations were conducted for seven days using MATLAB/Simulink R2019b. Identical demand and PV profiles were applied across all models, and the initial and end-of-week SOC conditions were set to prevent significant energy imbalances between consecutive weeks, enabling the weekly results to be annualised. Seasonal variations in demand and PV generation were not considered; therefore, the annual costs represent estimates under the assumed representative-week conditions. The 15-year economic evaluation included initial, operating, and replacement costs and subsidies. The minimum evaluation period required for the lowest-cost model to become more economical than the normal charging model was also investigated.

The planned-purchase V2X model achieved the lowest annual average cost over 15 years at 16.147 million JPY/year, 6.7% lower than the normal charging model. Its annual power purchase cost was reduced by 2.735 million JPY, and the accumulated savings offset the additional V2X and reused-LIB costs. The model became more economical from six years onwards. In contrast, the zero-purchase V2X model eliminated grid power purchase costs but had the highest annual average cost because of the large reused-LIB capacity and increased BG maintenance costs. These results indicate that planned V2X operation with moderate battery capacity provides a better balance between equipment investment and power purchase cost reduction than eliminating grid power purchases.

Power systems are becoming increasingly dependent on flexible loads capable of supporting system operation as renewable resources penetration levels increase. In this context, hydrogen electrolyzers are not only large controllable loads, but also potential providers of ancillary services if their power electronic interface and control are properly designed. However, their low voltage and high current characteristics impose demanding requirements on the power electronic interface used to connect them to the AC grid.

Most reported grid-connected electrolyzer power chains are based on voltage-source rectifiers followed by one or more DC/DC stages. Although this architecture provides a high degree of controllability, the additional conversion stage increases the number of semiconductor devices, passive components and control loops. This becomes relevant for industrial scale hydrogen electrolyzers, where very high current operation, conversion stage reduction, reliability, and control simplicity are important design considerations. Current source rectifiers (CSRs) provide an alternative architecture due to their inherent buck characteristic, which is suitable for the low voltage and high current operating conditions to be obtained directly from the AC grid in a single conversion stage. Recent developments of parallel, interleaved, and multilevel current source converters for high power electrolyzers further highlight the industrial interest in this type of interface.

This work investigates a single stage CSR for directly supplying a PEM electrolyzer using an adaptive lead-lag current controller. The proposed controller extends and applies an adaptive methodology previously developed for a DC/DC buck converter to the higher order dynamics of the CSR. A complete averaged model in the synchronous dq frame is developed, including the AC-side LC filter and the operating point dependent electrolyzer load. The dominant low frequency current dynamics are identified from the complete model and used to obtain a reduced first-order representation for controller design. The controller coefficients are updated online according to the electrolyzer operating point and the desired transient response, while the complete sixth-order CSR model is used for validation.

The results demonstrate consistent current responses over a wide electrolyzer operating range and accurate tracking of variable current references. In addition, the system is evaluated under a severe 50% AC side voltage sag. Despite the resulting transient increase in the AC side current and temporary dip in the DC current, the CSR remains controllable and the electrolyzer current recovers to its pre-disturbance reference in approximately 50 ms.

Although voltage source converters remain the dominant industrial grid interface, these results show that a CSR can provide current regulation and voltage ride-through capabilities required from a grid connected electrolyzer interface.

Offshore HVDC transmission systems are increasingly used to integrate large-scale renewable generation into weak or converter-dominated grids, where stability is governed by converter control dynamics, synchronization, AC/DC coupling, fault recovery, delay effects, and network strength. Although impedance-based analysis, small-signal modelling, and EMT simulation are widely used for stability assessment, practical grid integration is often organised around compliance-oriented EMT test procedures defined by transmission system operators. The link between converter-driven phenomena, test procedures, observable signals, and diagnostic metrics is therefore still not always explicit.

This paper proposes a compliance-oriented EMT test matrix for offshore HVDC systems. The matrix maps dynamic phenomena to test objectives, observable signals, diagnostic metrics, key parameters, and relevant HVDC architectures. Although developed for offshore HVDC grid-integration studies, where offshore power-plant behaviour, export-cable dynamics, and weak onshore connection points may interact through the HVDC link, the matrix is formulated as a general test-selection and interpretation framework for converter-dominated HVDC integration scenarios.

The approach is demonstrated using a representative point-to-point VSC-HVDC EMT model in MATLAB/Simulink. Four selected matrix entries are analysed: phase-angle steps, voltage-magnitude steps, a three-phase fault, and a measurement-delay case, corresponding to synchronization response, voltage-disturbance and AC/DC coupling, fault recovery with converter-current stress, and delay robustness. The results show that the tests provide complementary diagnostic evidence and should not be treated as interchangeable stability indicators. Severe fault tests alone are therefore insufficient for assessing weak-grid-related stability issues. The study is simulation-based and intended as a framework demonstration, not as a complete validation campaign.

To achieve carbon neutrality, the integration of renewable energy sources is expected to expand significantly. However, there are concerns that this expansion may deteriorate the supply-demand balance of power grids and lead to a decline in grid frequency stability. To address this issue, adding fast frequency response (FFR) control to grid-following (GFL) inverters has attracted much attention recently. Since GFL inverters are simple in configuration and low-cost, FFR-type GFL inverters serve as a readily deployable measure for grid frequency stabilization.

FFR achieves a faster response than the conventional governor control of synchronous generators by controlling power output of battery energy storage systems based upon measured frequency values. While FFR performance is directly linked to measurement accuracy, the existing standards are limited to accuracy requirements under steady-state conditions. Consequently, the dynamic input-output characteristics of frequency meters remain unclear. These include the tracking capability and errors of the output signal in response to sudden changes in the input signal, such as amplitude, phase, and frequency variations, and evaluation indices for these characteristics have not been established.

This paper evaluates the dynamic input-output characteristics of frequency meters based on experimental results. To evaluate these characteristics on a Bode plot, the three-phase voltage waveform, which serves as the input signal to the frequency meter, was slightly amplitude-modulated by another low-frequency sinusoidal wave. Specifically, the input signal v(t)=(V0+X*sin(2pi*delta_f*t))*sin(2pi*f0*t) was applied, and the output signal, grid frequency f(t)=f0+Y*sin(2pi*delta_f*t+theta), was measured. From these measurements, the gain Y/X and phase shift theta of the specified low-frequency sinusoidal wave superimposed on the nominal frequency were determined.

In the experiments, a Typhoon HIL simulator implementing a grid disturbance model and the power meter were used. Three-phase voltages superimposed with amplitude-modulated signals (amplitude: 1–10%, frequency: 1–10 Hz) generated by the Typhoon HIL were amplified to 100 Vrms using a bipolar power supply and fed into the frequency meter. The measured data and RMS values output from the meter synchronously were acquired via Ethernet communication using TwinCAT control software.

The experimental results showed Bode plots representing the gain and phase characteristics of the meter input and output, using the modulation frequency range of 1 to 10 Hz as a parameter. Since the gain and phase shift between the input and output are not constant relative to the modulation frequency, these results clearly suggest a non-trivial transfer function within the frequency meter. To improve FFR control performance of GFL inverters, the design of the FFR controller should include these dynamic characteristics of the frequency meter.

The full paper will describe the results of identifying the transfer function between frequency meter input and output. Furthermore, by incorporating the obtained transfer function into the GFL inverter model, the stability of the FFR control system is evaluated under different short-circuit ratio conditions using Nyquist plots and pole maps.

In response to global warming, the deployment of distributed energy resources based on renewable energy has been expanding. However, since these resources are connected to the power grid via inverters, they have lower inertia than conventional synchronous generators, leading to a reduction in overall power system inertia. As a result, deterioration of frequency stability is a concern, and a decrease in short-circuit capacity has also become an issue. To address these challenges, grid-forming inverters (GFMs) have attracted increasing attention.

GFM inverters provide virtual inertia by emulating the characteristics of synchronous generators, thereby contributing to improved frequency stability during power system disturbances. However, since they operate as voltage sources, they tend to produce overcurrent during disturbances such as ground faults.

The authors have previously proposed an overcurrent suppression method for GFM inverters using a current limiter applied to the instantaneous values of three-phase AC currents. Although the method effectively suppresses overcurrent during faults, it causes waveform distortion in the output current during the suppression period.

This paper investigates an overcurrent suppression method combining virtual resistance and active power reference control. The proposed method is evaluated using time-domain simulations, with particular attention to the transient response associated with circuit breaker (CB) reclosing.

Simulations were carried out using the simulation model shown in Fig. 1. A three-phase-to-ground fault was applied at the midpoint of one of the two transmission circuits at t = 3.00 s. The CB on the faulted circuit was opened at t = 3.05 s and reclosed at t = 3.20 s. The initial active and reactive power references were set to 0.8 pu and 0.0 pu, respectively, and the current limiter threshold was set to 1.0 pu. The proposed method was validated by comparing the GFM inverter output current waveforms and transient responses during CB reclosing with those obtained using the conventional method based solely on a current limiter.

Simulation results showed that the proposed method effectively suppressed the GFM inverter current within 1.0 pu during the ground fault. Furthermore, the waveform distortion observed with the conventional method was reduced. The proposed method also suppressed the overcurrent caused by phase deviation immediately after CB reclosing.

The full paper will further investigate the effects of parameter variations on the overcurrent suppression performance of the proposed method.

In recent years, environmental and energy issues have gained global significance, leading to the expanded integration of renewable energy sources. In battery energy storage systems (BESS), equipping grid-following (GFL) inverters with fast frequency response (FFR) control has attracted attention as an effective means to mitigate grid frequency deviations. These deviations are caused by fluctuations in power output from increasing renewable energy and the reduction of power system inertia due to a decrease in synchronous generators.

Large-scale green hydrogen imports require low-carbon conversion of hydrogen carriers at the receiving terminal. This study evaluates an offshore wind-integrated ammonia cracking coupled with molten salt-based thermal energy storage (TES) for a supply chain from Australia to South Korea. Offshore wind generation near Ulsan was estimated from 2023 data for eight 15 MW turbines, while the ammonia cracking process and dynamic TES behavior were modeled. Wind electricity was prioritized for direct electric heating and TES charging; grid electricity supplied deficits, and surplus wind power was exported. The wind power plant achieved a capacity factor of 41.7%. The integrated process reached an NH₃ conversion of 98.31%, and two alternately operated molten salt tanks achieved a storage utilization factor (SUF) of 77.5%. The green ammonia pathway yielded a base-case levelized cost of hydrogen (LCOH) of 7.06 USD/kgH₂ and a carbon intensity of 3.25 kgCO₂-eq/kgH₂. The results indicate the potential of high-temperature TES to shift wind-derived energy into continuous hydrogen production, while highlighting the remaining influence of ammonia cost and grid-supported operation.

Tamil Nadu is at the forefront of India's renewable-energy transition, with installed renewable capacity reaching approximately 29.8 GW by July 2026, including about 14.1GW of solar and 12.3GW of wind. The increasing penetration of must-run inverter-based renewable generation is progressively reshaping system operation through thermal-generation backing-down, reduced synchronous-machine commitment, changing system strength, greater renewable forecasting dependence, and increasingly demanding real-time balancing requirements. These challenges now coexist with record system demand: Tamil Nadu reached an all-time peak demand of 21,724 MW on 14 July 2026 and record daily energy consumption of 475.447 MU on 17 July 2026. During high-renewable periods, wind and solar together have supplied a substantial share of daily energy, creating operating conditions characterised by high inverter-based resource penetration, steep net-load ramps, renewable variability and reduced synchronous support.

As this transition progresses, maintaining frequency stability, system strength, voltage regulation and adequate reactive-power support becomes increasingly important, particularly in renewable-rich and electrically weak corridors. Grid-forming (GFM) PV-BESS can provide capabilities including fast frequency response, virtual inertia, voltage formation and dynamic reactive-power support; however, the principal operational challenge is moving beyond the question of whether GFM technology can provide these functions towards determining how much GFM capability is required, where it is required, when it should be available, and whether sufficient capability exists in real time.

This paper presents a practical, system-oriented framework for assessing GFM capability for frequency control, using the Tamil Nadu power system as a representative high-renewable case. The proposed approach combines demand and renewable forecasts, synchronous-generation commitment, frequency-security indicators, short-circuit ratio (SCR), voltage and reactive-power conditions, renewable forecast uncertainty, network contingencies and system ramping requirements to identify temporal and locational GFM needs. Available GFM capability from PV-BESS resources is assessed considering battery state of charge, active- and reactive-power headroom, converter availability and local grid strength.

Particular attention is given to multi-inverter coordination, GFM–GFL interoperability, protection adaptation under converter-limited fault-current conditions, and SOC-constrained provision of frequency-support services. The study further proposes a real-time GFM sufficiency assessment that compares required and available capability as system conditions evolve.

Finally, the paper advances the concept of GFM capability as a future ancillary system service, enabling grid-forming resources to be forecast, scheduled, coordinated and monitored through day-ahead assessment, intraday reassessment and real-time sufficiency monitoring. The framework provides a practical pathway for integrating GFM-enabled PV-BESS into grid codes, system operation and future ancillary-service arrangements for secure operation of renewable-dominant, low-inertia power systems.

Keywords— Grid-Forming, PV-BESS, Frequency Control, GFM Adequacy, Ancillary Services, SCR, Renewable Integration, Tamil Nadu.

The increasing penetration of electric vehicles (EVs) in low-voltage distribution networks has introduced new challenges related to harmonic emissions, particularly under AC charging. These emissions often result in harmonic unbalance across the three phases, primarily due to the heterogeneous integration of single-phase and three-phase EVs, along with diverse charger configurations operating within the same network. Additionally, recent measurement-based studies have demonstrated that the harmonic distortion of on-board chargers increases when the charging current is reduced from its rated level.

The central research question addressed by the “Fuchstal leuchtet” project is whether and how stable grid operation can be achieved within a purely inverter-based island grid (grid-forming and grid-following converters) based on their applicable technical connection rules (TCR). This includes island grid operation as well as the transition between synchronous and island mode, and vice versa. Given recent advancements (e.g., VDE FNN Guideline “Technical requirements for grid-forming capabilities including provision of inertia”), operational requirements now define the synchronous control behavior of grid-forming (GFM) inverters, supplementing the established TCRs for grid-following (GFL) systems. While another paper examines the process of intentional islanding with GFM and GFL inverters, which will be examined practically in the 3rd field trial, this study focuses on the evaluation of the synchronous grid operation capability of the two GFM inverters, based on the manufacturer's parameterization according to the VDE FNN Guideline.

• Voltage source behavior
• Active power response to a phase angle step
• Effective impedance
• Response during underfrequency and overfrequency ranges (PCNB)
• Continuous voltage control – Setpoint response
• Damping of power-frequency-oscillations
• Response to steep frequency gradients (RoCoF)

The full paper provides a detailed explanation of the individual tests according to the VDE FNN guideline and their possible implementation in the field lab, demonstrating the extent to which the GFM inverters comply with these requirements. Building on the simulation results, a field test will be conducted in coordination with the distribution system operator (DSO). This practical trial aims to validate the simulation results using specific, feasible scenarios thereby demonstrating the reliable synchronous operation of GFM units in the distribution network.

Sub-synchronous oscillations are a major concern within the GB transmission system. Specifically in central and southern Scotland, where minimal synchronous generation remains on the network, several complex oscillations have been detected. Likely due to the connection of a significant number of inverter-based resources. This paper presents the work in detecting, analysing and mitigating a sub-synchronous oscillation problem that affected the system for a decade which was solved in March 2026 by employing a collaborative, non-fault approach between the involved parties. ScottishPower Transmission’s expansive wide-area monitoring system was utilised to gather event data, before dissipating energy functions were applied to track the oscillation energy path. Phasor measurement units correctly identified the participants, but the deployment of waveform monitoring identified complex, higher frequency, coupled, positive and negative sequence components indicating an event with significant unbalance. Live system tests were conducted to assess the impact of the greatest participant which showed the oscillation removed from the system when the device disconnected. Saturation of a single phase was detected demonstrating the effectiveness of the complex oscillation tracking performed with the waveform monitoring units. Remedial action was taken and participation in the mode was not observed when the device returned to service.

Container terminals are under growing pressure to decarbonize while maintaining reliable and cost-efficient operations. However, many port energy management systems (EMS) still rely on simplified demand profiles, isolated asset models, or decisions disconnected from terminal logistics, limiting their ability to represent electrified port operation and reducing transferability across terminal layouts. This paper proposes a renewable-integrated port microgrid EMS for container terminals, using the Port of Sines as an operational case study. The framework combines a backbone economic dispatch problem with modular asset-level models for photovoltaic generation, battery energy storage, onshore power supply (OPS), flexible loads, and non-flexible terminal demand. A logistics-to-energy interface links the EMS to a SimPy-based container terminal simulator, converting vessel calls, OPS connection windows, crane activity, and reefer container locations into structured electrical demand inputs. The OPS module represents the operational and economic trade-off between shore-side electricity and auxiliary engine operation, while renewable generation and storage dispatch are coordinated within the same scalable optimization structure. The resulting MILP formulation minimizes operating costs under operational and electrical constraints and supports scenario analysis of renewable integration, grid import, storage dispatch, OPS supply, and future asset extensions, including additional renewables, forecasting modules, and electric vehicle charging.

Large-scale integration of inverter-based resources (IBRs) poses critical challenges for power system stability, as grid services once provided by synchronous generation must now come from IBRs as well. Inertia has been widely acknowledged as one of the most urgent. Beyond the total amount, the spatial distribution of inertia shapes both local response (RoCoF, instantaneous frequency deviation) and wide-area phenomena (damping, inter-area oscillations). Unlike conventional plants, which are at fixed locations with regular operating cycles, renewable plants are widely distributed and highly variable: when inertia is provided by IBRs as well, this might result in continuously shifting of the inertia distributions across the system.

This work investigates how heterogeneous inertia distributions affect the dynamics of the Continental Europe system, using a modified open-access large-scale dynamic model. Several configurations are tested with phasor RMS simulations and dedicated performance metrics.

Public electric vehicle (EV) charging stations must make real-time scheduling decisions under stochastic arrivals, heterogeneous charging demands, and time-varying electricity prices. In practical deployments, operator priorities such as profit maximisation and user satisfaction vary with congestion levels and grid conditions, requiring scheduling policies that adapt to changing system states and operational objectives in real time. Optimisation-based scheduling methods rely on fixed objective weights and require repeated re-optimisation when preferences change, limiting their applicability under operational constraints. Existing learning-based approaches often employ value-based action selection across the full preference space, which can lead to abrupt policy changes when priorities shift and reduced Pareto front coverage due to conflicting gradients during training. To address these limitations, we develop a preference-conditioned multi-agent reinforcement learning framework based on a value-decomposition actor-critic architecture. The objective preference space is partitioned into subspaces, and policies are trained sequentially with parameter transfer to improve coverage across competing objectives. At runtime, a rule-based controller switches among the trained policies according to observed queue congestion and grid capacity, enabling adaptation without retraining. Simulation results on real-world ACN-Data, averaged over 50 Monte Carlo runs, show that our approach improves Pareto front coverage compared to baseline methods, reduces peak-hour queue length by up to 25%, improves charging completion rates, and maintains millisecond-level inference latency. The approach can be integrated into existing charging station management systems without requiring changes to hardware infrastructure, enabling practical deployment under real-world operating conditions.

The share of renewable energy sources (RES) within the power system is increasing rapidly, with wind energy and photovoltaics becoming the most dominant sources. As a result, these fluctuating generators must transition from being pure energy suppliers to active contributors to security of supply and grid stability. Consequently, stable grid operation is becoming increasingly complex. A critical aspect of this transition is the provision of reactive power, a task that has traditionally been the responsibility of large-scale conventional plants at the transmission level but is now shifting towards decentralized units.

Recent system disturbances, among them the Iberian event of 28 April 2025, have highlighted the role of overvoltage dynamics and transmission–distribution interaction in system stability. Distributed generation (DG) may disconnect rapidly during faults, removing active power and reactive-power absorption. Remedial-action schemes are increasingly used at distribution level and could change the distribution-side operating point deliberately and near-instantaneously in fault events, further changing dynamic behaviour. This paper identifies the distribution-side parameters governing the transmission-side response and assesses the effects of an Emergency Control Automatic (ECA) and simplified distribution models. A transmission benchmark is coupled to a wind-dominated 110-kV corridor with generic WECC type-4 plants. In the benchmark, ECA operation relieves the distribution-corridor loading but increases the distribution-side voltage, with a smaller increase at the transmission-side observation point. At the 220-kV observation point, the capacity-matched and equilibrium-matched dynamic equivalents overestimate the ECA increment by 0.19 and 0.83 percentage points, respectively, whereas static equivalents reproduce the pre-event voltage reasonably well but understate the increment. At fixed cos φ = 0.95 underexcited, a larger HVRT-capable share reduces the overvoltage, whereas insufficient HVRT capability may turn the planned ECA into full DG disconnection. A large-scale synthetic combined-grid case shows a local voltage effect that decays rapidly in a meshed transmission grid.

Synchronous generators are the primary voltage sources in electrical power systems and play therefore a central rule to voltage regulation. As voltage is a local value subject to both slow variations (e.g., load changes, network topology modifications) and fast disturbances (e.g., short‑circuits), maintaining system voltage within TSO grid‑code limits is essential for equipments protection, losses minimization, and overall system stability.

Renewable hydrogen produced via water electrolysis has a pivotal role in decarbonizing the hard to abate sectors. As water

Hybrid power plants combine dynamic response assets such as wind power, photovoltaic systems, battery energy storage systems and STATCOMs under the supervision of a Hybrid Power Plant Controller. The ability of such plants to provide grid code compliant ancillary services depends not only on the control design of the Hybrid PPC, but also on the interoperability characteristics of the individual assets, including communication latency, controller processing delays and inverter response bandwidth. This paper investigates interoperability aspects in HPPs providing voltage control and power oscillation damping services. Different HPP control topologies and cascaded control architectures are analysed, with particular focus on the impact of communication and control delays between the Hybrid PPC, subsidiary controllers, and dynamic assets. Transfer function based analyses and model based assessment studies are used to evaluate the influence of interoperability limitations on voltage control performance and POD-Q behaviour under representative grid code requirements. The results show that voltage control can tolerate moderate delays while still complying with response time, settling time and overshoot requirements, whereas POD-Q performance is significantly more sensitive because additional delays directly introduce phase lag into the damping response. Based on the analysis, recommendations are provided regarding communication architectures, controller integration and asset qualification to support reliable implementation of voltage control and POD-Q functionality in multi-vendor HPPs. The paper intends to contribute to improved grid code compliance and more robust operation of future HPPs.

The total share of renewable energy (RE) in Scotland currently exceeds 170% of electricity consumption, contributing significantly to the UK’s overall RE share reaching 50%. The wind share is particularly high, already exceeding 130%, which is likely among the highest in the world.

1. Voltage fluctuations initially
2. Local disconnections followed by some successful and unsuccessful attempts at reclosure
3. A final stage of widespread, rapid voltage and frequency collapse.

1. if voltage fluctuations can be managed robustly, disconnections are less likely and in turn,
2. if reclosures after disconnections can also be managed robustly,
3. the frequency collapse that marks an actual blackout can be avoided.

• placement and selection of measurements to achieve system awareness by means of state estimation,
• secure, resilient and efficient information and communication architectures and interfaces,
• integration of market-based and grid-oriented optimizations to control PV and generation, consumption, and prosumers such as storage systems.

Renewable Energy communities (RECs) can enable grid integration of decentralized renewable energy by coordinating local renewable generation, storage and flexible and unflexible loads, thereby improving local system balancing and providing flexibility to support a more efficient distribution network operation. Therefore, the large-scale deployment of RECs is seen as an additional key driver for the integration of renewable generation and power system decarbonization.

Modern grid codes require validated impedance models to assess stability in converter-dominated systems. Since field measurements yield site-specific results, test benches with grid emulators are increasingly utilized. Nonetheless, grid emulators exhibit background harmonic noise. Annex E of IEC 61400-21-4 proposes a procedure to assess this influence and can also be used to determine the Thévenin equivalent of the device under test (DUT). However, practical experience with the method is still limited. This paper addresses this gap through investigations on a multi-megawatt Vestas wind turbine at the Dynamic Nacelle Testing Laboratory (DyNaLab) of Fraunhofer IWES. As Annex E provides sparse practical guidance, specific methods for implementation, outlier detection, and filtering are proposed. The results confirm that the method is capable of determining the impedance of the DUT but requires careful evaluation of the measurements to ensure sufficient spectral content by varying testing configurations. It proves particularly effective for estimating impedance trends in the high kHz range, where grid emulators often lack harmonic injection capability, and may thus serve as a valuable complement to classical impedance scans.

In the transition toward decarbonized energy systems, hydrogen technologies are emerging as key enablers. Solid oxide electrolysis cells (SOECs) offer the highest efficiencies among electrolyser technologies. However, their perceived thermal constraints have limited their consideration for transient operation and, consequently, for the integration of fluctuating renewable electricity in both off-grid and grid-connected applications. This study challenges that perception by demonstrating the potential and feasibility of SOEC systems to provide grid-relevant ancillary services while enabling direct integration with renewable energy sources.

Our research presents three major advancements in grid-integrated and off-grid SOEC operation, exploring and demonstrating the capability of SOECs to provide ancillary grid services, including fault ride-through (FRT) as well as frequency and voltage control. First, we introduce and validate an advanced operating strategy for dynamic SOEC operation. Pulsed operation using pulse-width modulation (PWM), switching the stack current between open-circuit and nominal operation, decouples electrical loading from the system’s thermal response. This enables rapid changes in power consumption while limiting temperature variations and thermal gradients. Experiments conducted on a multi-stack SOEC system, pressurized up to 25 bar and integrated into a complete Power-to-X (PtX) process, demonstrate rapid modulation of the duty cycle over a range of 10-100 %, resulting in fast changes in average power consumption with only small temperature variations. The results demonstrate a dynamic range comparable to proton exchange membrane (PEM) electrolysers without compromising stack integrity, substantially increasing the potential of SOEC systems to provide grid-balancing services. Second, simulation-based analysis of LV-FRT scenarios shows that SOEC systems can tolerate severe faults, recover rapidly and contribute to grid stability when operated under appropriate control strategies. Third, for off-grid applications, we investigate the potential of reversible SOEC operation in fuel cell mode to provide backup power for standalone, renewable-driven electrolysis plants. This is particularly relevant when coupled with power-to-X (PtX) processes – such as Fischer-Tropsch, methanol, methane, or ammonia synthesis – which require continuous power supply. An extended simulation study, based on a validated multi-stack module model and a plant design, optimized for efficient SOEC operation, quantifies the achievable backup power output in fuel cell mode.

Overall, the results demonstrate that SOEC systems can evolve from steady-state hydrogen producers to flexible, multi-functional assets that actively support grid stability and renewable energy integration.

Grid-forming converters are expected to become a key capability for maintaining stability in power systems with high shares of inverter-based generation and storage. Their defining characteristic is not the injection of predefined active or reactive current, but voltage-source behavior behind an effective impedance. During severe disturbances, however, the resulting current may exceed the converter capability. Current limitation is therefore unavoidable, but introduces an additional degree of freedom: the current magnitude must be limited, while the current angle can either be preserved or deliberately modified to prioritize active or reactive current. This paper assesses active-current priority, reactive-current priority and current-angle neutral scaling from a system-level perspective. The results show that active- and reactive-current priority each support specific stability objectives, but their benefits depend on disturbance type and plant operating mode. Scaling preserves the direction of the unconstrained voltage-source response and avoids imposing a single-objective priority on the system. It is therefore proposed as the robust standard behavior for grid-forming converters under current limitation.

The accelerated interest in Electric Vehicles (EVs) has brought substantial changes to both transportation and energy infrastructures. Therefore, there is an imperative need to explore unified models to address both logistics and power grid operations simultaneously. For this reason, this research reviews current studies on integrated energy-logistics models designed to facilitate the grid integration of EVs, focusing on EV routing, EV charging infrastructure, and the electricity market. The literature mainly addresses these aspects by analyzing the effectiveness, limitations, and challenges that constrain real-time applicability. Several modeling deficiencies are identified, such as poor scalability, inability to address uncertainty effectively, lack of multi-level cooperation between EV fleet operators and grid stakeholders and lack of utilizing data-driven and hybrid optimization techniques. In particular, many models fail to capture temporal-spatial relationships in EV routing decisions and the uncertainty in EV charging demand, renewable power supply, and power system constraints. Thus, this review provides a research agenda for developing co-optimization approaches with real-time decision-making and renewable power forecasting capabilities to facilitate the scalable adoption of integrated energy-logistics models for EV grid integration and EV fleet operations.

Offshore Wind Power Plants (OWPP) are essential to achieving Europe’s decarbonisation and energy security objectives. As new projects are developed farther from onshore grid connection points and at larger scales, the complexity of their transmission systems continues to grow. In several markets, developers are responsible for the engineering, construction, and sometimes operation of the offshore transmission grids, making early-stage design decisions critical to project costs, risks, and business-case viability. This paper presents a methodology and sets of best practices for the early-stage design of High-Voltage Alternating Current (HVAC) transmission systems for large OWPPs. The proposed approach supports developers in progressing from limited preliminary information toward technically robust and commercially viable transmission concepts aligned with project constraints, state-of-the-art technologies, grid code requirements, and regulatory frameworks. Key techno-economic decisions are addressed, including the selection of transmission system topology, reactive power compensation strategy, harmonic compliance requirements, and identification of essential input data, modelling assumptions, and grid studies. The paper also examines cable active power transfer capability and loading limits as well as the impact of regulatory frameworks on the design decisions. The methodology is practiced on two study cases from Vattenfall’s offshore portfolio and supported by PowerFactory-based grid modelling and simulation studies.

Hydrogen production through grid-connected electrolysers is expected to support the integration of renewable energy, long-duration storage, and the decarbonisation of hard-to-abate sectors. However, large-scale electrolyser deployment introduces new grid integration challenges, particularly as emerging network codes redefine electrolysers as dynamic grid participants rather than passive electrical demand. Conventional grid compliance testing relies on full-stack operation, resulting in continuous hydrogen production, increased operational risk, and high energy consumption during testing.

This study proposes a Power Hardware-in-the-Loop (PHIL) framework for running grid compliance type tests on electrolysers. In this approach, electrolyser stack behaviour is emulated in real time using an aggregated dynamic Electrical Equivalent Circuit (EEC) model. This paper focuses on the development and validation of the real-time-compatible EEC model of an Anion-Exchange Membrane (AEM) electrolyser to reproduce key electrolyser characteristics, including current–voltage behaviour, dynamic electrical response, and hydrogen production rate. The model output was validated against experimental current–voltage data. Furthermore, the flexibility of the modelling framework is demonstrated through its adaptation to represent alternative electrolyser technologies, such as membrane-less electrolysers.

The validated EEC model reproduced the electrolyser's key performance characteristics with sufficient fidelity to replace the physical stack during selected real-time PHIL grid-compliance and converter-interface tests, while preserving electrical behaviour at the converter interface. This reduces reliance on live hydrogen-producing equipment during compliance assessment, improving safety, reducing costs, allowing faster testing, and lowering energy consumption.

The accelerated expansion of variable renewable energy (VRE), particularly wind and solar photovoltaic generation, has introduced significant operational challenges for large interconnected power systems. Among the main impacts are the reduction of aggregated electromechanical inertia, increased variability in the load-generation balance, intensified bidirectional power flows, and growing complexity in frequency and voltage control. These changes are reshaping operational requirements associated with system adequacy, reliability, and stability, while simultaneously influencing long-term expansion planning and electricity market design.

The increasing adoption of rooftop photovoltaic (PV) systems, heat pumps (HPs), electric vehicles (EVs), and battery energy storage systems (BESS) in residential areas poses technical challenges for low-voltage (LV) distribution grids, including voltage violations, higher losses, and increased peak loads. However, the combined, incremental impact of these technologies on Swedish residential LV grids remains unexamined. This study assessed these impacts via alternating current (AC) power-flow simulation of a 47-villa LV radial feeder in Eskilstuna, Sweden, across four seasonal weeks, investigating the impacts of (i) electrical distance between electrified villas and the transformer, and (ii) incrementally adding different levels of electrification and storage across the feeder. The magnitude, duration, and system losses due to voltage violations increased with the electrical distance between electrified villas and the transformer. HP and uncontrolled EV charging caused winter undervoltage and higher peak load, while rooftop PV caused overvoltage in spring, summer, and autumn. Adding BESS and vehicle-to-home (V2H) reduced voltage violations and losses, and reduced peak load, while increasing PV self-consumption (SC) and self-sufficiency (SS) relative to the fully electrified case without storage. In most cases, BESS outperformed V2H due to its constant availability. These findings show that feeder location, technology mix, and storage jointly determine grid impact.

Medium-term forecasts of electric vehicle charging-station utilization, from several months up to one year ahead, are essential for infrastructure planning and operation. They support decisions such as defining site power limits for dynamic load management and sizing local battery storage. However, station-level forecasts are challenging when only limited local observations are available and when charging behavior is noisy, site-specific, and strongly influenced by local context. This work proposes a multi-site transfer learning approach for forecasting the future power utilization distribution, energy, and maximum power of charging stations. The approach combines short observation windows from the target station with extended station metadata, including station type, geographic context, and proximity-based descriptors. We benchmark feedforward Neural Networks (NN), XGBoost, the tabular foundation model

The integration of large-scale offshore wind generation into modern power systems demands extensive studies to ensure reliable and secure operation. These studies must address multiple aspects, including steady-state behavior such as voltage profiles, active and reactive power requirements, and dynamic performance during transient events like faults. The complexity increases significantly when offshore wind farms are considered for black start restoration, as this abnormal operating condition introduces unique challenges in both steady state and transient conditions of each restoration step. One of the challenges in system restoration planning study is to sift through numerous possible restoration scenarios and paths to identify those that are technically feasible.

In this paper, the recommendations of the ENTSO-E Expert Panel regarding the grid incident on the Iberian Peninsula are compared to the German Grid Code requirements and the conformity assessment procedure. The comparison shows that several recommendations are already reflected in the German technical connection rules, particularly regarding the technical capabilities of generating units and their verification during planning and commissioning. However, the analysis also identifies areas for further development, especially concerning recurring verification during operation, data availability, existing units and restoration-related requirements. Drawing from these results, FGH presents an ongoing research project on automated compliance testing during the operational phase of power plants and discusses how automated testing infrastructure could support both certification processes and ongoing operational monitoring.

As power systems transition toward configurations with increasing shares of inverter-based resources (IBRs), transient stability assessment becomes more challenging. Conventional time-domain simulations provide high-fidelity results but are computationally expensive and typically yield binary stable/unstable classifications. To support applications requiring fast transient stability assessment, screening methods based on transient energy functions, extended equal-area criteria, and related direct methods have been proposed. Their main advantage is computational speed, achieved through significant model simplifications. While these methods are well suited to simplified contingency screening, the required simplifications can limit their applicability to planning and detailed system analysis. This work adopts and extends classical metrics developed for synchronous generators, specifically center-of-inertia-corrected dot products and rotor-angle coherency, for transient stability assessment of IBR-rich power systems. These metrics are evaluated using the full implemented model without network reduction or the model simplifications associated with direct methods. They capture the relationship between power imbalances, speed deviations, and angular dispersion and are combined into a Composite Severity Index. Based on short post-fault responses, these metrics transform multivariable trajectories into quantitative measures of transient severity, enabling contingency ranking and providing a continuous stability metric that can be incorporated into optimization frameworks to quantify system-level transient stability requirements.

Due to the significant expansion of offshore grid connections expected in Germany in the coming years, a substantial contribution to grid stability is required from DC-connected Wind Power Plants (WPPs). In this context, grid-forming (GFM) capabilities are mandated by the grid codes, which also address inertia provision among other features. While the wind industry is making relevant progress in developing products capable of providing GFM capabilities, proper coordination with the High-Voltage Direct Current (HVDC) system is essential to efficiently transmit the inertia contribution of the WPP to the onshore network. In this scenario, two German TSOs, TenneT and Amprion, along with the HVDC division of Siemens Energy (SE), have conducted feasibility studies in 2025 to further investigate the potentials and limitations of such systems in providing inertia contribution at the onshore connection point of an HVDC offshore WPP connection. This paper presents the main outcomes of this collaboration, demonstrating that by implementing a GFM control at both converter stations of the HVDC system, it is possible to efficiently transmit the contribution of the WPP to the instantaneous reserve provision at the onshore connection point, without the need for signal telecommunication.

• Design of the measurement campaign: Selection of key grid parameters (frequency, voltage, active/reactive power), placement of measurement devices, and synchronization with grid events.
• Data acquisition and processing: Techniques for high-resolution data collection, filtering, and analysis to capture dynamic grid behavior and disturbances.
• Model development and validation: Simulation models (aggregated and detailed model in DIgSILENT PowerFactory and PSCAD) and their validation and bechmarking against measurement data to ensure accuracy in representing grid interactions, control strategies, and system services.

• Challenges in coordinating measurements with grid operators and managing data quality.
• Insights into model validation and the importance of accurate parameterization for reliable simulation results.

The increasing penetration of renewable energy sources (RES), particularly wind and solar power, introduces significant challenges to power system stability, especially regarding frequency control.

The rapid electrification of the transport and the integration of renewable energy (RE) are imposing stability challenges on the power-grid. These stability issues are driven by the large scale integration of controlled power-inverters, which alters the grid dynamics and reduces inherent damping. This paper examines railway grid instability in comparison to other inverter based resources (IBR). These phenomena, although documented for years, are occurring more frequently and more severely in railway power-grids. This is largely driven by ongoing vehicle renovations and the widespread deployment of modern power-electronics across Europe and Asia. The railway represents a distinctive case in which instability arises from the interaction between grid weaknesses and the inverter-based rolling stocks rather than originating from the power sources, as is the case in RE systems. As such, the railway case may provide a valuable glimpse into the future behaviour of power grids under widespread EV integration and increasing reliance on RE. The study addresses this issue from a theoretical perspective, highlighting the similarities and differences in contributing factors across sectors. It identifies the structural and operational distinctions between cases. Through comparative analysis, this work aims to clarify the challenges associated with the transferability of solutions and supports robust stability strategies for future power systems.

The secure and efficient operation of extra-high voltage grids is a central task of transmission system operators. Accurate grid calculations that account for uncertainties are essential to detect congestion events early. With the substantial expansion of solar and wind generation and the associated weather-data uncertainty, potential congestion events may occur that must be prevented or mitigated. This contribution presents a case study of Germany’s transmission system to quantify and evaluate weather-related uncertainties affecting power flow, taking ensemble-based forecasts into account. The aim is to investigate the effects of ensemble forecasts on the loading of transmission lines and to derive initial insights for grid operation. The freely available SimBench grid model is used and extended with ensemble forecasts at grid node level for solar and wind generation. The study analyzes a full-resolution grid model in an hourly resolution using DC power-flow calculations with the open-source software pandapower. Both probabilistic and deterministic methods are applied to analyze the distribution of line loadings. The results show that the use of ensemble forecasts has a direct impact regarding the possible loadings of the transmission lines within the grid calculation and leads to different spreads of line loadings. These spreads show that the use of ensemble forecasts for wind and solar generation can lead to advantages in grid operation and congestion management. The uncertainties arising from different feed-in values may provide system operators with a better insight into possible congestions.

Maintaining resilient, grid-independent energy supply is necessary for critical infrastructure, yet often limited by renewable vari-

Brazil's National Interconnected System (SIN) is now one of the world's largest wind markets, with a fleet that has nearly doubled since 2020 and is overwhelmingly concentrated in the Northeast and South subsystems. As wind penetration deepens, fast variations in aggregate generation - wind ramp events - are emerging as a first-order operational constraint, driving reserve sizing, flexible dispatch and electrically-driven curtailment. Yet a country-wide, plant-level characterization of ramp frequency, severity and seasonality based on official operator data has not been published for Brazil.

With the increasing integration of power electronics, accurately representing converter-based resources in power system studies has become essential for analyzing their interactions with the grid. These converters consist of two main subsystems: a power electronic stage based on controllable switches (e.g., IGBTs modules) and a fast-acting control system. Due to their inherently fast dynamics, their transient behavior cannot be properly captured using classical RMS (Root Mean Square)-based phasor models. For this reason, Electromagnetic Transient (EMT) simulations are increasingly used to study converter–grid interactions as well as interactions between converters closely located in the AC grid, as they can represent fast switching and control dynamics with high fidelity. However, applying EMT models to large-scale networks with thousands of nodes is computationally expensive and often impractical for system-level studies.

The rapid penetration of wind and solar generation in the Brazilian Interconnected System has shifted the role of transmission: lines feeding the renewable-rich Northeast and South corridors toward the Southeast load centre have become the binding constraint on the financial viability of variable renewable energy. Their failures translate increasingly into curtailment of wind and solar generation, measurable welfare losses, redispatch and ancillary-service costs, and contractual exposures under the concession regime. This study develops an integrated economic framework that quantifies, exclusively from public-domain data, the joint cost of energy not served (valued by three complementary methods), the Variable Parcel imposed by Brazilian regulation, the redispatch triggered by the contingency, and the curtailed renewable energy that would otherwise have flowed through the affected corridor.

The accelerated penetration of variable renewable energy sources (VRES) in Brazil — particularly utility-scale wind and solar plants alongside the exponential growth of distributed micro and mini generation (MMGD) — has driven a sharp increase in

The rapid integration of inverter-based renewable generation is reshaping power system dynamics by reducing system strength, inertia, and conventional reactive power support, thereby introducing significant stability challenges in weak-grid conditions. While many existing studies rely on single-machine infinite-bus representations, such models do not fully capture the coupled interactions among multiple converters in renewable-rich networks. To address this gap, this paper investigates a Multi Converter Infinite-Bus (MCIB) system comprising Grid Following (GFL) solar and wind farms operating under extremely weak-grid conditions. The study further evaluates the role of a Grid Forming STATCOM with Energy Storage (GFM e-STATCOM) as a stabilizing asset capable of actively supporting voltage regulation, damping converter interactions, and improving stability. Detailed simulations developed in PSCAD/EMTDC demonstrate that the GFM e-STATCOM effectively smooths system dynamics, enhances transient and small-signal stability, and enables stable operation across severe grid-strength variations. The results establish GFM e-STATCOM as a scalable and practical solution for strengthening MCIB networks and supporting the reliable integration of large-scale renewable generation.

As inverter-based resources (IBRs) are deployed at ever-increasing scale across transmission, distribution, and customer networks, the fundamental nature and capabilities of power systems are undergoing a profound transformation. This shift leads to a loss of inertia and effective short-circuit strength, creating new stability challenges. Stakeholders worldwide are increasingly recognizing the need for additional inertia and enhanced system support and are examining how grid-forming (GFM) technologies can be deployed and integrated as ancillary services. For example, in 2023 the German Federal Network Agency initiated market-based procurement schemes for inertia and other grid-forming capabilities. In this context, the Forum for Network Technology and Network Operation in the VDE (FNN) released the second edition of its guideline, which defines the requirements for units that wish to participate in the German inertia market. The guideline and its technical descriptions are pioneering in this field. The next step is to validate and demonstrate the applicability of the defined tests in practice.

In a grid-forming (GFM) modular multilevel converter-based high-voltage direct-current (MMC-HVDC) system, one terminal operates under dc-link voltage control, while the other operates under active power control. This paper analyses the inertia response of the dc-link voltage-regulated MMC. It is found that when frequency disturbances occur in the dc-link voltage-regulated MMC-connected grid, the remote ac grid can provide inertia support through dc-link voltage-to-active power droop control. However, this paper reveals that, although remote grid energy can be utilized for inertia support, inertia provision capability is constrained by dc-link voltage and dc-link current limitations. In addition, this study quantifies the inertia provision capability boundary within those limitations. Simulation results validate the accuracy of the derived boundary.

• identify where and when to invest in infrastructure,
• optimize the utilization of existing assets,
• and reduce connection request backlogs.

TBA

Growth in large loads, particularly data centers, is driving dramatic change to power systems planning in multiple regions around the world. Their unprecedented concentration in power demand, high but uncertain growth, and dynamic demand profiles create unique risks to system reliability and affordability. This presentation will examine how these planning challenges are occurring in the United States and describe mitigation options for these risks. It will show leading load forecasting practices that could reduce uncertainties. Tariffs and other regulatory or policy options have also been rapidly developed to protect other customers from the potential cost impacts. The presentation will also explore flexibility from the loads themselves--through load curtailments, load shifting, and associated generation or storage (e.g., bring-your-own-capacity) options--that can further mitigate risks and enable large loads to be grid assets rather than liabilities. The presentation will summarize work from the Energy Systems Integration Group's Large Loads Task Force, which convened stakeholders across the power systems and data center industries to identify practical solutions and develop harmonized practices that ensure reliable and efficient grid integration of large loads.

Building the Future Grid: Strategic Transmission Planning to Achieve VRE at Scale

The transition from unidirectional smart charging (V1G) to bidirectional charging (V2G) promises additional operational flexibility and reduced electricity costs for facilities. However, the economic value of this transition is not universal and depends strongly on facility-specific characteristics, including load profiles, electricity tariff structures, charging infrastructure, EV participation, and battery utilization. Whether the additional investment for V2G pays off therefore remains a key question for facility operators. This paper proposes a simulation-based techno-economic framework that addresses this question by combining smart charging simulation with a cost-benefit assessment covering electricity tariffs, power prices, infrastructure investment, battery compensation, and operational costs to estimate annual savings, payback period, and return on investment. The framework is demonstrated on a real municipal hospital in Dresden using measured load profiles and realistic EV charging scenarios. Results show that discharge capability is a key determinant of economic performance. Under both investigated AC configurations, the achievable peak reduction remains below the economic break-even requirement, indicating that the V1G-to-V2G transition is not economically viable under the considered site conditions.

vRE forecasting is one of the crucial initiatives to support the effective grid integration in the context of energy transition in Indonesia. This would contribute to more safe and economic operation of the power system. GIZ is working on a demonstration project to introduce a scientific operational vRE forecasting system in Indonesia. vRE forecasting model is being implemented for Solar in Jamali system and Wind in Sulawesi system. In the initial phase, the major power plants that are focused are 143 MWp Cirata Solar PV park, 25 MWp Kubu plant and 75 MWp Sidrap farm. The methods of Numerical Weather Prediction based day-ahead predictions , satellite imagery based intra-day predictions and combination techniques are utilized to come up with accurate forecasting methods. The vRE forecasting model results are benchmarked with measured data to provide insights on the model improvements. This is one of the first attempts on step-by-step scientific vRE forecasting in Indonesia and is expected to contribute crucial insights for the utility (PLN).

Definition of an Energy Storage Strategy for Portugal in 2040 - TBC

The European Union (EU) Network Code on Requirements for Generators (NC RfG) defines the technical requirements that generating and storage units must comply with prior to connecting to the power grid. While it entered into force in 2016, it is currently undergoing an amendment process to reflect the latest changes in the European power grid, including more robust requirements in the context of a growing penetration of converter-based generation and storage.

The amended Regulation, the so-called NC RfG 2.0, is expected to enter into force by the end of 2026/early 2027. The draft version consultated by the European Commission (EC) during July and August 2026 includes non-exhaustive grid forming requirements for non-synchronous generating and storage units, such as synthetic inertia provision and voltage source behind an impedance behaviour. These requirements vary depending on the type (i.e size) of unit, being mandatory for some cases while subject to a national decision for others.

Once the NC RfG 2.0 enters into force, the European Network of Transmission System Operators for Electricity (ENTSO-E) is legally mandated to draft Implementation Guidance Documents (IGDs), publicly consult them, and publish them within 6 months after the entry into force. These documents aim at guiding system operators, which are not bound to follow them, with the national implementation of the non-exhaustive EU NC RfG 2.0 requirements that must be exhaustively defined in the national Regulations.

This is the case for the grid forming requirements of NC RfG 2.0 and, consequently, ENTSO-E is currently developing an IGD on this topic. This IGD builds on the previous ENTSO-E's report from the Technical Group on Grid Forming Capability (TG GFC), where ENTSO-E engaged with relevant stakeholders and included their feedback. The report was publised in November 2025 and available here: https://www.entsoe.eu/news/2025/11/04/entso-e-publishes-phase-ii-technical-report-on-grid-forming-requirements/.

In a nutshell, the main outcomes of the ongoing IGD will be presented. The IGD proposes detailed requirements on the grid forming requirements of the draft NC RfG 2.0: i.e., on the voltage source behaviour behind an impedance within capability limits, on the synthetic inertia contribution within capability limits, and on the behaviour when reaching capability limits. Furthermore, it also recommends some principles to verify compliance with these requirements.

Increasing penetrations of rooftop PV and, just in 2026, home batteries: Australia has just installed 12,000MWh in 9 months, versus 20,000MWh in utility-scale BESS.

Project presentation: AHEAD project (https://horizon-ahead.eu/)

Power System Stability Needs Assessment Framework