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.

High-power electric vehicle (EV) charging can create power peaks that exceed available distribution-grid capacity. This paper investigates retired Leclanché GL60 G/NMC cells from the 4.3 MWh Ellen e-ferry battery system as stationary buffers for grid- constrained DC fast-charging sites. A one-minute time-domain simulation combines a 500 kW grid connection, 300 kW double charging stations, stochastic daily demand, a Danish time-of-day arrival pattern derived from Campus Bornholm measurements, and a battery model with SOC, C-rate, efficiency, grid-recharging, and capacity-fade constraints. Sites with one to six stations and 6, 9, 12, or 20 sessions per day per station are evaluated. The minimum buffer is identified in 25 kWh increments subject to less than 0.5% annual unmet energy. Degradation is estimated using equivalent full cycles, manufacturer cycle-life data, and calendar-aging sensitivity. Required capacity ranges from zero to 1.025 MWh. For six stations at 20 sessions per day per station, the minimum buffer experiences approximately 236 EFC per year and reaches 70% SOH after approximately 7.2 years under the

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

N-1 voltage security is a critical issue for transmission systems.

Harmonic compliance is necessary for obtaining energization (EON), interim (ION), and finale (FON), operational notifications, for grid-connection of the inverter-based resources (IBR) plants to the distribution and transmission grids. Generally, the harmonic compliance shall be proven by simulation studies using harmonic impedance envelopes.

The harmonic impedance envelopes represent operation regimes of the grid, are provided by the grid operator, and may range from tens ohms up to several thousand ohms for each relevant integer harmonic and interharmonic order. The grid operator may request the simulation results for the impedance envelopes with 1-ohm resolution. Commercially available methods will conduct load-flow (LF) followed by harmonic load-flow (HLF) simulations in each point of the impedance envelopes for each harmonic order that is an accurate but time-consuming approach.

This paper discusses accuracy of a fast simulation method introduced by AFRY Denmark A/S for assessing harmonic compliance of inverter-based resource (IBR) plants. The fast simulation method interpolates the solution for the entire impedance envelope through a couple of critical points instead of executing LF and HLF. Accuracy of the method is achieved by constructing and solving a type of optimization functions, while impedance/frequency scans and harmonic amplification calculations to establish harmonic voltage or current magnification may introduce unacceptable inaccuracies.

Accuracy of the fast simulation method is demonstrated by direct comparison to the exact solution by a commercially available method utilizing LF and HLF simulations. The fast method applies for both the IEC (balanced) and the Phase-Correct (unbalanced) harmonic assessments at high accuracy and with an execution speed that is up to hundred times faster than conventional methods. The demonstration is given by real-life, anonymized cases.

Meeting future inertia requirements and ensuring grid frequency stability are key challenges resulting from the energy transition. One solution is the hydraulic variable inertia flywheel, developed at Flensburg University of Applied Sciences. When designing the flywheel, sustainability aspects must be considered alongside functionality. Therefore, this article aims to identify the most sustainable material for construction. In addition to conventional manufacturing materials such as steel and aluminium, the three most common 3D printing filaments – acrylonitrile butadiene styrene (ABS), polylactic acid (PLA), and polyethylene terephthalate glycol-modified (PETG) – are considered. A stress calculation is used to determine the required wall thicknesses and material masses for various flywheel sizes. Subsequently, the energy output during a frequency decrease from 50 Hz to 47.5 Hz is calculated. To assess sustainability, the carbon-specific energy in kWh/kg CO₂ equivalent is evaluated. The carbon-specific energy increases steadily with increasing radius up to the strength limit, which is reached at a radius of 0.48 m. As steel is the most sustainable material, a construction made out of steel with largest possible radii is recommended. This article emphasises the importance of a sustainable optimisation and provides important findings for the further development of the hydraulic variable inertia flywheel.

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, showing good agreement between measured and simulated total losses across the investigated P–Q operating range. The results provide a field-data benchmark for validating loss-estimation models for utility-scale PV power plants.

This paper looks into the ability of grid forming inverters to compensate harmonic oscillations of the voltage. The ability to act as a sink for harmonic voltage oscillations is a demanded characteristic for inverter controls to be classified as grid forming. In this paper three methods are used to analyse this ability. At first, an analytical approach is chosen to identify the frequency range in which the grid forming inverter control is damping harmonic voltage oscillations of the external grid. This analytical approach is then verified in simulations, whose scope is then extended to replicate a real voltage grid from a field measurement campaign. To conclude the investigations measurements from a field measurement campaign in an island grid, fed purely by inverters, are analysed. The goal of this paper is to analyse and quantify the ability of grid forming inverters to act a sink for harmonic voltage oscillations, to identify the impact of parameterisation of the inverter control on this ability and lastly to assess the accuracy of analytical and simulation-based approaches to replicate this behaviour.

Power systems with increasing shares of wind and solar are experiencing greater intra-day variability, ramping requirements and dependence on flexible resources. Tamil Nadu provides a relevant operational testbed because of its large renewable portfolio, significant industrial Open Access participation and rapidly growing solar utilisation. Its textile, automotive and other C&I sectors increasingly procure renewable energy through captive and Open Access arrangements, while emerging EV charging and data-centre loads add further flexibility requirements. This paper presents a data-driven assessment of solar photovoltaic–battery energy storage system (PV–BESS) integration under 15-minute scheduling, incorporating time-of-day tariffs, deviation exposure, network-loss treatment and Open Access energy accounting. Utility-derived records from two operating PV–BESS installations examine surplus daytime solar storage, measured BESS discharge and subsequent consumer adjustment. By shifting solar energy to the 18:00–22:00 evening peak, BESS can reduce grid imports when applicable C&I tariffs carry a 25% premium. A scheduling framework incorporating state-of-charge, charging/discharging limits, losses, tariffs and deviation costs is formulated to improve net deliverable energy and reduce peak-period dependence. The study also discusses voltage support, fast frequency response and future grid-forming functionality.

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.

The rapid transformation of power systems is accelerating the need for new forms of flexibility. While traditional sources of flexibility—such as thermal plants and large‑scale storage—remain important, attention is increasingly shifting toward large electrical loads capable of providing fast, controllable demand. Industrial‑scale electrolysers are among these emerging flexible assets. Unlike traditional passive loads, converter‑dominated loads interact with the grid across a wide frequency range, with behaviour shaped by control loops, DC‑link dynamics, and internal process characteristics. These interactions can give rise to adverse effects such as harmonic amplification and small‑signal instabilities, particularly in weak grids. As the penetration of such loads increases, understanding their frequency‑dependent behavior becomes essential for stable system operation. This paper addresses this challenge by developing a comprehensive analytical impedance model for large electrolysers. The analytical formulation provides a transparent and computationally efficient tool for small‑signal stability assessment.

Grid reinforcement and expansion are essential to accommodate increasing shares of variable renewable energy sources (VRES), but investment lead times may not align with the rapid deployment of distributed photovoltaic (PV) generation. This paper examines whether Distribution System Operators (DSOs) can increase grid hosting capacity through improved connection-study practices and operational measures, in addition to conventional reinforcement. A questionnaire covering voltage assumptions, connection studies, technical solutions, cost allocation and network planning was answered by 13 distribution system operators or national experts from 11 countries. The results reveal substantial differences in the voltage headroom reserved for photovoltaic connections to low-voltage networks, ranging from 1% to 6%, as well as in the use of measured voltage data, reactive-power control, curtailment, smart transformers, storage and demand-side management. Simplified connection-study thresholds also vary significantly across jurisdictions. The comparison indicates that conservative static assumptions can materially restrict photovoltaic hosting capacity, while measured data and more adaptive technical criteria may enable additional connections without immediate grid reinforcement. Greater transparency, common metrics and comparative assessment of connection practices could support more efficient and proportionate integration of distributed renewable generation.

Series capacitors (SCs) are widely used in long transmission lines to reduce the effective series impedance and increase power transfer capability. During faults, SCs are typically protected by metal-oxide varistors (MOVs) against excessive currents and overvoltages. Owing to their nonlinear voltage-current characteristic, MOVs provide a low-impedance path when a predefined voltage threshold is exceeded, thereby limiting the electrical stress on the SC. Under severe fault conditions, the SC–MOV system may also include a bypass switch that can be rapidly triggered to reduce the stress on the protection equipment. Accurate modeling of SC–MOV systems is essential for reliable power system stability assessment. Recently, the Western Electricity Coordinating Council (WECC) approved a phasor-domain transient (PDT) model based on the Goldsworthy MOV formulation. This well-established formulation has historically been used primarily for steady-state short-circuit studies. However, its application in PDT simulations has not been widely documented or systematically evaluated in the literature. This paper investigates the capabilities and limitations of the SCMOV model in PDT studies. Its performance is systematically assessed for MOV conduction and bypass operation and benchmarked against electromagnetic transient (EMT) simulations, which provide a more detailed representation of system behavior. The analysis also evaluates the impact of the SCMOV model on the simulated behavior of inverter-based resources, whose active and reactive power injections, as well as blocking behavior, are highly sensitive to large terminal voltage excursions.

Data centres are becoming a growing share of electricity demand, representing a new class of large, dynamic loads that challenge traditional power system operation and analysis. System operators, including in Australia, are developing technical requirements for secure integration of data centres. Fault ride-through (FRT) compliance has emerged as a key concern following incidents where data centres disconnected during voltage disturbances. Uninterruptible power supply (UPS) architecture strongly influences FRT performance, which may be centralised at the facility or decentralised at the rack level. This paper fundamentally evaluates the withstand capability of data centres equipped with centralised and decentralised UPS systems under different system strength conditions. We clarify how critical data centre loads can be shared between the grid and UPS backup following voltage disturbances, considering power distribution equipment limits. During high-voltage disturbances, data centre withstand capability is constrained by equipment voltage limits, while during low-voltage disturbances grid power is limited by equipment current ratings. The simulation results demonstrate that the post-disturbance dynamics of hyperscale data centres are strongly influenced by UPS active power recovery and converter protection, with recovery-induced voltage excursions or sustained voltage depression becoming particularly significant under weak grid conditions. These findings highlight the need to explicitly represent UPS dynamics, rack-level battery response, and converter protection in dynamic models to accurately assess data-centre voltage stability and grid impact.

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.

In this study, 526 existing wind power plants in Sweden were assessed for retrofitting with photovoltaics (PV) using a Boolean overlay approach. The analysis includes suitability layers covering suitable, unsuitable, protected nature, national-interest, and forest-specific categories, together with restricted and buffered layers accounting for solar irradiance, infrastructure, terrain, and proximity constraints. The results show that: (i) the PV retrofitting power potential ranges from 1.15 to 12.90 GW, with forest land inclusion being the dominant driver; (ii) the hybrid power plant (HPP) qualified area increases substantially more than the potential retrofitting PV area when additional suitable layers such as forest and agricultural land are included, suggesting that the limiting factor is not land availability but rather the point of interconnection (POI) capacity; (iii) the retrofitting PV capacity potential increases approximately linearly with the buffer distance; and (iv) the energy yield of the 13 retrofitted parks shows that the solar-to-wind ratio ranges from 0.25 to 0.95 with only 1% curtailment on average. Finally, the framework can be easily adapted to other regions or applied to different retrofitting projects.

This paper thoroughly compares and presents two extended grid-forming (GFM) control methods, Synchronverter (SV) and

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.

Capacity-based state of health is an incomplete basis for deciding whether aged electric-ferry cells should remain in service or be reassigned to second-life use. This study reframes aged e-ferry cell evaluation as a sequential life cycle decision and extends earlier cell-to-cell analysis in the previous study by adding more diagnostic metrics and explicit cycle-to-cycle analysis from repeated complete cycle windows. A simulated daily ferry driving/charging profile is used for first-life extension, while low-rate and C/2 efficiency, voltage repeatability, apparent resistance, and 168 h rest behavior are used for second-life screening.

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).

The increasing penetration of renewable generation and other inverter-based resources (IBRs) is reducing system inertia, short-circuit strength, and voltage stability margins in modern power systems. Hybrid Synchronous Condenser Systems (H-SCS), which combine a Synchronous Condenser System (SCS) and a Static Synchronous Compensator (STATCOM) at a common point of coupling (PCC), provide an effective solution to these challenges. This paper presents operational experience from the Phoenix H-SCS installation in Scotland and describes further developments incorporated into the Eccles project.

The increasing penetration of power electronic converters has given rise to emerging stability phenomena requiring new approaches to stability assessment. While electromagnetic transient simulations reveal unstable behaviour, impedance-based analysis provides insight into converter-grid interactions and offers greater computational efficiency. Accordingly, this paper investigates how converter-level outer-loop control influences the small-signal stability of grid-following voltage-source converters connected to a weak grid. A generic 120 MVA power park is modelled in PSCAD, with outer-loop control implemented locally at converter level. Reactive power and AC voltage control are compared on the q-axis, while active power and DC-link voltage control are compared on the d-axis. Converter self- and transfer admittances are extracted through a 1 200 Hz frequency scan and combined with an analytical grid impedance to form the converter-grid loop gain. Stability is assessed using Bode and Nyquist analysis. The results show that outer-loop control affects damping characteristics and resonance frequencies. In particular, AC voltage control introduces asymmetric damping around the fundamental frequency, resulting in supersynchronous interactions. Differences between the d-axis configurations are most pronounced around the fundamental frequency and become small above twice the fundamental frequency. The findings show that outer-loop control should be considered in grid-connection studies of converter-connected devices.

With the growing deployment of inverter-based resources (IBRs), particularly grid-forming (GFM) assets, power-system behaviour during the first cycles after fault inception and clearance is becoming increasingly relevant. Existing fault ride-through (FRT) requirements predominantly specify RMS-based behaviour and provide only limited guidance for fast electromagnetic transients. Recorded fault events and simulation studies indicate that phase-angle jumps, transient overvoltages, high rates of change of frequency (RoCoF), and control-related interactions can occur in this time frame and may lead to unintended disconnections of converter-based assets.

This paper presents the framework and key findings of the OptiTransient project. The analysis combines recorded real-world high-voltage fault events, EMT simulations, and laboratory measurements. Relevant transient phenomena are characterised and their dependence on grid-following (GFL) and GFM control structures is assessed. Particular attention is given to converter current-limitation strategies, which strongly influence transient voltage behaviour, available instantaneous power reserve, and post-fault recovery.

EMT studies of future grid configurations show that increasing GFM penetration can improve the damping of transient oscillations and reduce voltage stress during voltage dips and phase-angle jumps. The results also identify converter current headroom and current-limitation design as key constraints for the effective provision of GFM-based instantaneous reserve, including from large battery energy storage systems.

Furthermore, measurements on different FRT test benches demonstrate that the realised transient voltage and current waveforms depend substantially on the test-bench topology and switching principle. An improved phase-wise, magnitude-based current-limitation approach for unbalanced faults is evaluated by simulation and software-in-the-loop testing.

The results provide a basis for measurable transient-performance indicators, realistic EMT studies, and reproducible test approaches for the further development of grid-code and test-bench requirements for converter-based generation and storage assets.

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.

The responsibility for voltage maintenance and reactive power management is increasingly shifting from transmission to distribution grids. The system operator’s control levers include transformer tap changer positions and, for renewable energy sources, reactive power setpoints and Q(U) characteristic curves. However, the system operators remain uncertain about the interactions among these reactive power and voltage control quantities. In particular, the interplay between Q(U) characteristic curves and reactive power exchanges with neighbouring network operators is causing concern amongst system operators. This paper addresses this issue and establishes the key performance indicators `reactive‐power provision efficiency' and `voltage sensitivity' to rate the suitability for reactive power control schemes. These key performance indicators are used to evaluate the correlations among different operating modes for specific assets in a small distribution network for several study cases and two topologies. The results are then generalised, and recommendations for system operators are derived.

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.

Photovoltaic plants coupled with battery energy storage systems require dispatch strategies that balance market operation, battery ageing, export-profile tracking, and PV forecast uncertainty. This paper presents a mixed-integer linear programming framework for hourly PV-BESS dispatch with grid charging, battery-throughput and curtailment costs, and soft export-profile tracking. Usable capacity is scaled by state of health, charge and discharge efficiencies are derived from round-trip efficiency, and binary constraints prevent simultaneous charge/discharge and grid import/export. The framework is evaluated for the Danfoss Solar Park in Nordborg, Denmark, using a 2.1 MW-peak PV plant, a 4.3 MWh BESS, PVGIS SARAH3 generation data, and DK1 day-ahead prices. Four seasonal days, five battery ageing cases, three PV forecast scenarios, and 6, 12, and 24 h model predictive control horizons yield 200 unique dispatch configurations. Averaged across forecast scenarios, the 6 h MPC yields a 21.28\% lower reported direct operating-cost component than the full-day open-loop optimization benchmark, but exported energy decreases by 457.23 kWh and export-tracking error increases by 502.33 kWh. The results show that short-horizon MPC can reduce the reported operating-cost component under PV uncertainty, but at the expense of weaker export-profile tracking.

I. MOTIVATION

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.

Due to the loss of power from synchronous generators, grid stability needs to be provided by new inverters with grid-forming (GFM) control. However the integration of GFM inverters to the low-voltage grid is still under discussion. Advantageous is the expected increase of resilience and security of supply of the LV grid during a power outage. Meanwhile, this is in contradiction to the anti-islanding required for grid-following (GFL) inverters for safety and operational reasons. It is expected that the stabilising behaviour of GFM control counteracts with the anti-islanding detection methods used, which are seeking to bring grid voltage and frequency out of limits.

In order to prove this thesis, a power hardware-in-the-loop test grid is set up consisting of a GFM inverter and different GFL photovoltaic inverters connected to an emulated utility grid. The grid is switched off at different power balances between the GFM

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.

The vast integration of renewable resources and inverted-based resources (IBRs) continuously transforms modern power grids, giving rise to new dynamics, considerations and potential solutions to issues in the grid. In the last few years, a plethora of IBR driven interactions has been documented across grids worldwide. An important aspect of studying and mitigating such interactions during planning is modelling detail. Those modelling details need to incorporate the wide frequency range and nature of such interactions, which are typically provided by electromagnetic transient type (EMT) models. This paper presents generic EMT models of converter enabled technologies including a Type-4 wind turbine and Multilevel Modular Converter (MMC) HVDC. Focus will be drawn in the grid-forming (GFM) capability of each technology. Using the developed models, the GFM mode of operation of these IBR technologies is investigated, and their technology readiness is studied. The effectiveness of these GFM technologies to address grid stability issues is tested in an 18-bus test system. The overall objective is to provide a set of generic GFM EMT models for various IBR technologies that can be used for long-term planning studies and highlight potential differences in response, or limitations.

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.

Grid-forming converters are expected to play an increasing role in converter-dominated power systems, while their required behaviour is becoming subject to formal verification. The VDE FNN guideline Technical requirements for grid-forming capabilities including provision of inertia defines extensive measurement-based procedures covering multiple operating points, disturbance types and test variants. Their reproducible laboratory implementation therefore requires considerable engineering effort.

This paper presents AutoTest, a modular automation framework that translates FNN verification procedures into reusable, parameterised and configurable test suites. A suite-generation layer on top of openSVP enables test sequences to be assembled, visualised and modified while keeping the test definition independent of the underlying laboratory equipment. Dedicated interfaces integrate the real-time simulator, power amplifier, high-rate measurement system, DC source and device under test. The real-time simulator provides deterministic generation of the required grid disturbances, whereas an independent measurement chain records the high-rate signals required for compliance assessment.

The framework is demonstrated using representative FNN procedures and an experimental grid-forming inverter. The architecture additionally provides a basis for automated post-processing and pass/fail evaluation without making these functions part of the time-critical test-execution layer.

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.

The publication of the draft 'Requirements for Generators 2.0' paved the way for grid-forming inverters to be integrated. Many manufacturers are now launching the first such devices on the market. However, these are designed for use with battery storage systems. The grid-forming operation of renewable energy systems, such as photovoltaic plants, is still a subject of ongoing research. Against this background, this paper examines an AC-coupled hybrid system comprising a grid-following photovoltaic unit and a grid-forming battery storage unit. The aim is for this hybrid system to operate in accordance with the requirements of the RfG 2.0 at its grid connection point. Therefore, the normative requirements are first outlined. Within the scope of this work, more detailed specifications refer to the requirements of the German VDE-FNN for grid-forming inverters. Based on these requirements, a realistic model of the hybrid system for the high-voltage range is shown, consisting of unit models, transformers, and a park controller. The simulations show that a large proportion of the grid-supporting measures are capable of meeting the regulatory requirements. Consequently, this type of plant offers an initial solution for designing renewable energy plants to support the grid.

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.

The article proposes a new method to model storage behavior in linear optimization long term energy planning models. The proposal allows eliminating the State of Charge equation in exchange for a data-driven approach, constraining storage discharge based on a dome-shaped constraint associated with storage capacity and power.

The proposal’s performance is tested against other commonly used methods across different data sequences. Model validation against a complete resource sequence demonstrates more than 90\% shortage coverage. All cases surpass the standard methodology with similar computational times. Sequential clustered methods are also outperformed when the number of clusters is low. Compared with complete sequential descriptions, the proposed method achieved 10\% lower deficit coverage, but with decreased computational time. The method showed robustness in system design, maintaining efficient computational times and reducing problem complexity.

The method has limitations to model several storage technologies or the resource-demand interaction. Nevertheless, the present approach is effective for highly flexible energy supply scenarios with only one type of energy storage (e.g.: solar or wind farm optimization).

Wastewater treatment plants (WWTPs) have a continuous electricity demand, generate and consume biogas on-site, and can shift selected process loads. Integrating wind and solar offers new revenue opportunities, but it can also create a generation-demand mismatch that results in renewable curtailment and expensive peak grid imports. We developed a sector-coupled model of a German WWTP with a population equivalent of 200,000 that includes wind, PV, on-site combined heat and power plant (CHP) units, demand-side load curtailment, and a 1MW/1MWh battery. We conducted a comparison of four scenarios (baseline, renewables, flexibility, and battery) under a conventional and a dynamic tariff using one year of measured plant and historical weather records. Renewable generation reduces annual grid imports by 52% to 67% relative to the baseline and raises self-sufficiency from 37% to as high as 79%. The technically optimal setup cuts the peak import by 43%, while the economically optimal configuration yields a positive project annuity of 177.5k€/yr. Adding the battery further raises self-sufficiency but reduces profitability, as the additional savings do not offset the higher capital expenditure. In our case, demand-side flexibility is far more cost-effective than battery storage, and because renewable output coincides with low market prices, dynamic tariffs add little extra value.

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.

Subsynchronous oscillations (SSO) have re‑emerged as a critical stability concern in modern electric power systems with grid forming (GFM) control. Traditionally, associated with interactions between synchronous generators (SGs) and series‑compensated transmission networks, SSO was categorized into subsynchronous resonance (SSR), subsynchronous torsional interaction (SSTI), and subsynchronous control interaction (SSCI). However, the rapid growth of inverter‑based resources (IBRs) in form of GFM-STATCOMs and E-STATCOMs has fundamentally reshaped grid dynamics.

1. Background

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.

This study expands the traditional comparison of the ``futures market vs spot market’’ in electricity procurement to include additional dimensions: the timing of contract signing and the flexibility provided by thermal storage for large-scale heat pumps in district heating systems. Using the example of disruptions to the German electricity market triggered by the 2021–2023 gas crisis, it examines when a heat pump operator should enter into a long-term supply contract and how this decision compares with active participation in the spot market. The analysis combines day-ahead prices, futures settlement data for annual, quarterly, and monthly products, as well as weather-dependent heat demand profiles, to quantify the trade-off between early hedging, finding the right time to buy or relying on fluctuating spot market prices through wind and solar integration.

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

The successful integration of renewable energy sources into power grids often requires the deployment of HVDC (High Voltage Direct Current) systems and/or FACTS (Flexible AC Transmission Systems). More recently, a new FACTS device for shunt compensation has emerged, namely the E‑STATCOM (Enhanced Static Synchronous Compensator), which combines reactive power compensation with fast active power exchange capability through the integration of a supercapacitor-based energy storage system (ESS).

The assessment of the high-frequency (HF) performance of an E‑STATCOM is key to its secure and successful integration into the grid. Therefore, electromagnetic compatibility (EMC), lightning surge, switching transient, and converter passivity studies should be conducted using accurate HF models of the ESS.

This paper presents Hitachi Energy’s recent experience in HF impedance characterization and modelling of supercapacitors for E‑STATCOM applications. Three-dimensional (3D) electromagnetic HF models of supercapacitor assemblies were developed using the software CST. Also using CST, the stray parameters of the various subcomponents were estimated to create equivalent circuit models in PSCAD/EMTDC. The developed HF models (both 3D and circuit) were then validated against laboratory measurements.

The proposed HF models and their validation through frequency-response comparisons, together with selected results from the system-level studies, are presented and discussed.

The energy transition with its simultaneous move towards renewable energy generation and electrification of mobility and heating poses new congestion management challenges for grid operators across all voltage levels. However, at the same time, it also provides new sources of demand-side flexibility to grid operators, which can help to mitigate those challenges. Redispatch 3.0 aims to use the flexibility of such small-scale decentralised loads to complement the existing cost-based redispatch regimes in Germany with a voluntary, market-based approach; thereby, integrating new types of flexibility for congestion management. Battery electric vehicle (BEV) charging is a particularly relevant example of demand-side flexibility, as the charging can often be shifted in time while still fulfilling the required energy demand of the BEV. This paper is structured in two parts. In a first step, the main concepts and ideas behind the Redispatch 3.0 scheme are introduced. These include participants, such as flexibility service providers (FSPs), who aggregate the flexibility of their customers on an asset-level and participate at flexibility markets, grid operators, who require flexibility to ensure a stable energy system as well as the various processes from the first aggregation of flexibility over activation of redispatch potential to monitoring and ex-post validation. In a second step, a real-world pilot between the FSP Octopus Energy Germany and TransnetBW as the transmission system operator is presented and first results are discussed in detail.

As renewable energy integration increasingly displaces synchronous generation, ensuring grid security under uncertain operating conditions becomes increasingly important. This paper proposes a continuous multi-period Chance-Constrained Security-Constrained Optimal Power Flow (CC-SC-OPF) formulation in the Nonlinear Programming (NLP) domain. The method

combines a rectangular-coordinate AC network representation with differentiable rational surrogates for scenario-based chance constraints, avoiding binary violation indicators while retaining the full non-convex AC network model. On a modified IEEE 9-bus system with S = 5 scenarios, the NLP formulation reduces execution time from 475.30 to 0.85 s (99.82%) relative to

the Mixed-Integer Quadratic Programming (MIQP) benchmark, with a 0.03% objective-value difference. For S = 10, the MIQP exceeds the 3 600 s time limit, whereas the NLP converges in 1.34 s. Scalability tests on IEEE 9-, 30-, 118-, and 300-bus systems demonstrate convergence for problems with up to approximately 1.9 million decision variables. These results demonstrate the

improved computational tractability of the proposed continuous reformulation for risk-aware power-system operation.

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.

Bidirectional charging (V2G) can reduce local distribution-grid peaks, but its value depends on how much flexibility is actually

Large-scale industries often deploy on-site fossil-fuel-based power sources alongside the central power grid to meet continuous high-power demand and reduce vulnerability, which increases their carbon footprint and operating costs. Appropriately sized renewable energy sources (RESs) and energy storage systems (ESSs) can meet demand during outages, reducing emissions and costs. However, accounting for techno-economic, operational, and weather-related variability of RESs remains a significant challenge. Several commercial and open-source optimisation tools have been developed and are widely used in industry to optimally size, plan, and manage RESs and ESSs, accounting for system integration, technical operations, weather conditions, expenditures, energy markets, and asset degradation. This article proposes a framework to optimally size, plan, and manage multi-energy systems for large-scale industrial plants by integrating power generation, storage, and the main grid, and compares it with existing optimisation tools. Power generation and storage capacities were compared based on different optimisation goals. The analysis uses identical power demand profiles, system configurations, and solver settings across all platforms, to the extent possible, to ensure a fair comparison. Some optimisation tools use preferred factors they consider necessary and lack transparency, which may lead to technically infeasible or economically suboptimal investment decisions in industrial energy infrastructure.

The Celtic Interconnector Project will deploy a 700 MW, 575 km HVDC link connecting the Irish transmission system to the continental European grid. It will be the first European HVDC interconnection between two asynchronous grids to operate with grid-forming (GFM) control mode enabled simultaneously at both converter stations.

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

Increased single-phase electric vehicle (EV) charging often causes phase unbalance in low-voltage networks (LVNs). This paper presents a dynamic assessment and mitigation framework that uses a linear model predictive control (MPC) approach to mitigate phase unbalance. EV data from Leeds and two representative UK low-voltage feeders were used for testing, comprising an urban feeder and a rural feeder. EV charging scenarios were constructed at 15-minute resolution under different EV scenarios.

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.

Electricity rates in Japan have been rising significantly due to soaring fuel prices and unfavorable currency exchange rates. Meanwhile, with the widespread penetration of rooftop solar power, feed-in tariffs have been declining gradually, making the shift from selling surplus power to self-consumption more economically advantageous. Additionally, as natural disasters such as torrential rainfalls and massive earthquakes become more severe and frequent, it is increasingly important for homes to maintain a stable power supply both in daily life and during emergencies. While household battery storage is gaining attention as a promising solution to these challenges, standard and simplified operating methods lack weather forecasting capabilities; consequently, these operating methods cannot adequately prepare for reduced solar output during periods of poor weather, such as continuous rainfall, making them insufficient.

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.

This paper investigates the dynamic stability of the Martinique Island grid with a 185 MW load and 19.38 MW of synchronous

This work applies compliance tests to a detailed grid-forming wind turbine model and derives Linear Parameter-Varying (LPV) equivalent models that adequately represent variations across operating points, control saturation, and resource constraints. The derived models are integrated into an aggregated frequency-dynamic framework, enabling scalable studies of large power systems with high grid-forming wind turbine penetration and low inertia. The proposed methodology establishes a systematic link between standardized compliance testing and large-scale dynamic system modeling. It thereby supports the development of realistic system-level studies for future low-inertia power systems.

This study addresses power system flexibility challenges in Kazakhstan and Uzbekistan under large-scale integration of variable renewable energy (VRE), specifically utility-scale wind and solar generation. By 2032, installed VRE capacity is projected to exceed 30 GW across the two countries, fundamentally changing system operation within the Central Asian interconnected grid, which is characterized by limited maneuverable generation, constrained transmission corridors, and centralized dispatch practices. Increasing shares of large-scale wind and solar significantly intensify residual load variability, ramping needs, and balancing requirements.

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.

In systems with high shares of weather-dependent generation, forecast uncertainty is increasingly recognized as an important driver of balancing needs, particularly in future system configurations where conventional thermal generation is expected to be progressively displaced by VRE.

This paper evaluates the impact of sector-coupling on VRE forecast-error-driven imbalance (FEDI) in future Nordic power systems. A large-scale, long-term, multi-sector energy-system optimization model is run with lead-time-aware, spatiotemporally correlated day-ahead wind and solar forecasts across multiple weather years, so that the operational representation reflects a forecast-based day-ahead schedule rather than a perfect-foresight schedule. Nordic VRE FEDI is derived as real-time VRE availability minus the day-ahead schedule, thereby capturing how forecast uncertainty changes the VRE position between scheduling and delivery. The resulting distributions are analysed using probability density functions, standard deviations and P05/P95 quantiles.

To examine how future system structure reshapes these imbalance statistics, the analysis considers four sector-coupling scenarios: (i) a fully coupled system including electricity, heat, hydrogen and transport; (ii) electricity, heat and transport; (iii) electricity and heat; and (iv) electricity only. These alternatives lead to vastly different electricity demands and represent distinct renewable-integration pathways, resulting in different VRE portfolios and consequently, different VRE-imbalance characteristics. The analysis shows that in 2045, VRE accounts for 55–79% of installed electricity capacity across the assessed sector-coupling pathways, while the Nordic VRE FEDI standard deviation ranges from 2.49 to 8.29 GW and the P05–P95 interval expands from approximately ±4.1 to ±13.5 GW.

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.

Understanding electric vehicle (EV) charging behaviour at public charging infrastructure is critical for effective network planning, tariff design, and policy development. This paper presents an observational study based on large-scale field data from the ChargePlace Scotland network, comprising nationwide public charging sessions across multiple local authorities and a diverse range of charging environments.

The increasing integration of renewable energy sources creates a need for reliable forecasts across multiple time horizons. While short-term and day-ahead power forecasting approaches are well established, longer range forecasting of renewable generation remains less explored. This study investigates the potential of seasonal climate forecasts for photovoltaic (PV) generation in Germany with lead times of up to six months.

The rapid development of the Central West Orana Renewable Energy Zone (CWO REZ) in New South Wales requires robust and scalable approaches to assess system stability as high volumes of inverter‑based resources (IBR) connect to a weak and evolving network. This work presents results of refined frequency‑domain stability assessment methodology developed and applied within the CWO REZ program during the past year. The approach integrates perturbation‑based impedance scanning in EMT, frequency‑domain evaluation in positive and negative sequence-domain impedance matrices, and cross‑validation with large synchronous condenser (SynCon) models to verify consistency between transfer‑function, state‑space, and impedance‑based representations.

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.

Although the publication of the revised European Network Codes (ENC) Requirements for Generators (RfG) and Demand Connection Code (DCC) has been delayed once again to 2026, the technical and regulatory requirements for electromobility have continued to mature within European expert working groups. In particular, further specification work has focused on electric vehicles (EV) and electric vehicle supply equipment (EVSE), reflecting their growing relevance for the overall system stability as active grid-connected resources rather than purely passive loads.

The study uses open-source grid-forming inverter and wind turbine data to simulate the dynamic behavior of wind turbines for the investigation of mechanical loads during grid events. A set of representative grid faults is simulated using a MATLAB/Simulink GFM Virtual Synchronous Machine (VSM) model, which is combined with OpenFAST aeroelastic simulations to analyze the turbine under turbulent wind conditions. The analyzed disturbances include voltage phase angle jumps, inter-area oscillations, and Rate of Change of Frequency (ROCOF) events, which represent critical perturbations commonly considered in compliance testing. Simulations are performed according to specifications defined in European grid codes, for different virtual inertia constants of the VSM. The simulations show that tower side-to-side bending moments are especially affected. In particular, frequency-related events show that higher virtual inertia in the VSM contributes to increased tower loads, indicating a trade-off between grid support capabilities and turbine structural loading.

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, a field test was conducted focusing 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
• Phase jump power
• Effective impedance
• Voltage source control –set‑point tracking behavior
• Voltage source control – Disturbance response and linearity of the effective impedance
• Damping of power-frequency-oscillations
• Provision of inertia (T_A)

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. Using the generated field measurement data, the reliable synchronous operation of the GFM inverters in the distribution network and their compliance with these requirements is demonstrated.

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.

To enable granular spatial planning under high distributed energy resource penetration, this paper proposes a multi-source hierarchical forecasting framework that reconciles net electricity consumption and installed solar self-consumption capacity. Utilizing real-world smart metering and production unit records from the E-REDES Open Data Portal, demand and capacity dynamics are modeled across four administrative levels in mainland Portugal: national, district, municipal, and parish tiers. Candidate baseline statistical models, including AutoARIMA, AutoETS, and MSTL, are evaluated alongside Bottom-Up, Top-Down, Middle-Out, and Minimum Trace (MinTrace) reconciliation techniques to guarantee strict spatial coherence. The empirical evaluation demonstrates that AutoARIMA paired with MinTrace reconciliation achieves optimal cross-hierarchy alignment, yielding the most robust continuous growth trajectories for solar self-consumption capacity. For net load forecasting, Top-Down reconciliation preserves macro-scale aggregate precision, whereas Bottom-Up captures localized consumption volatility driven by behind-the-meter PV adoption at the granular parish level. Furthermore, spatial disaggregation of the reconciled forecasts identifies critical high-growth expansion clusters, equipping distribution system operators with actionable insights to prioritize local grid reinforcements and effectively mitigate hosting capacity constraints. Overall, this framework optimizes model selection to support data-driven distribution network planning.

With the growing share of inverter-based resources (IBRs) in electric power systems, the risk of oscillatory events in the sub-, supersynrchonous and harmonic frequency range increases. Various methods have been proposed to identify critical network conditions and calculate margins in the mentioned frequency ranges for system stability. As part of the publicly funded project “SysStab2030”, a selection of methods, including the impedance-based stability analysis (IBSA), matrix-valued vector fitting, the direct evaluation of state-space models and the quantifying mode damping method (QMD) are investigated. Depending on the method, different metrics are calculated to quantify stability margins, such as phase, gain and modulus margins, as well as damping ratio of modes. The methods and metrics are compared by applying them to benchmark networks. It is found that all investigated methods can identify unstable cases and oscillations when compared to EMT time domain simulations. However, the ranking of the criticality in stable conditions differs between the evaluation of the damping ratio and the other margins. The metrics complement each other since the damping can reveal modes close to instability, whereas low phase or gain margins can point out frequencies at which high amplitude oscillations may occur.

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.

Increasing utilization of the low-voltage (LV) grid, driven by heat pumps, distributed energy resources, and electric vehicles (EVs) with bidirectional charging capabilities, introduces new operational challenges. In particular, charging/discharging of EV fleets can lead to local congestion and voltage deviations. Traditional grid operation approaches are not designed for these bidirectional and dynamic power flows, while many existing EV fleet control strategies focus primarily on economic optimization without fully considering their impact on grid behaviour.

The results show that the framework maintains soft real-time operation under the investigated conditions and that grid-dependent setpoint modifications are reflected in the applied fleet energy and EV state of charge.

Climate-neutral energy supply is leading to a shutdown of fossil-fuelled power plants, higher electricity demand and higher transmissions and causes an increasing demand for grid inertia. In future, renewable energy sources with grid-forming capabilities will need to provide grid inertia in order to cover demand in a climate-neutral manner. The replacement of fossil-fuelled power plants with renewable energy sources, a change is not only observed in the technology itself, but also in the voltage level at which they are connected. In addition to larger power plant systems operating at extra-high and high voltage levels, renewable energy sources are distributed across medium and low voltage levels. Therefore, the paper investigates the equivalence of inertia power and inertia energy when supplied from different voltage levels.

In order to achieve this objective, a cross-voltage-level SimBench grid has been configured in PowerFactory, encompassing high, medium and low voltage levels, with a transfer station to the extra-high voltage level. In the reference grid, existing battery storage systems are dynamised using grid-forming models of virtual synchronous machines. A comparison between inertia provision of a single grid-forming battery storage system connected at the extra-high-voltage level and that of distributed battery storage systems from the distribution Grid is drawn. In dynamic RMS simulations, defined active power disturbances are applied and the frequency gradient, as well as the inertia power and energy, are evaluated. The investigation of this influence is conducted by considering various steady-state operating conditions and fault directions.

The results show that grid-forming battery storage systems can provide inertia power at all voltage levels considered and contribute to short-term frequency stability. In all the cases examined, the amount of inertia power made available is greater for positive disturbances than for the corresponding negative disturbances. In the cases examined, the inertia power does not correspond to the magnitude of the active power disturbance. Depending on the operating condition, the power flows and thus the grid losses vary.

The transition to electric heavy-duty fleets requires coordinated planning of charging infrastructure and grid capacity, yet infrastructure decisions are often made under limited information and uncertain grid capacity. This is a major challenge, since grid expansions can be infeasible, costly, or slow to implement, making early estimates of the required charging capacity essential. This paper introduces a planning framework that links a small set of fleet-level statistics to a mixed integer linear programming (MILP) model that estimates the minimal grid connection capacity required for early-stage fleet electrification planning. A structured survey collects these statistics, which a stochastic assignment process converts into a synthetic fleet for the model to optimize charging schedules against. The methodology is demonstrated through a case study of a Danish grocery retailer's food distribution fleet, spanning a partial electrification level of 33 trips and a full electrification level of 120 trips served by battery electric trucks (BETs), performing a mix of regional and long-haul deliveries. Results show that optimized charging reduces the required grid connection capacity by up to 75% compared to uncoordinated charging. Full electrification still requires this capacity to increase by at least 2.5 times, to 2800 kW, driven primarily by the fleet's shift mix. Under a minimal connection objective, charging depots approach an almost constant load. A battery energy storage system (BESS) adds only marginal further reduction, since BET charging is already tightly packed throughout the day. The proposed method offers a low-data entry point for early-stage planning and is particularly relevant in contexts with limited grid availability or long connection lead times, supporting both grid planning and charging infrastructure design decisions.

Multi-vendor (MV) interoperability is a key prerequisite for the development of robust and expandable multi-terminal (MT) HVDC grids; however, the design of individual subsystems, such as converter and DC switching stations, as well as the control, operation and protection of the DC network, remain challenging. To address this, the EU-funded InterOPERA project is deploying a real-time demonstrator of a MT MV HVDC system. The preparation phase included the definition of a functional framework and its application to the selected topology, resulting in detailed technical specifications supported by HVDC grid design studies.

The increasing integration of renewable energy sources and growing network loading intensify the need for efficient utilisation of existing transmission infrastructure while maintaining N-1 security. Grid boosters (GBs) provide a fast curative congestion management measure by modifying power flows following a contingency. This paper proposes a methodology for the technical evaluation and placement of GBs in transmission networks and demonstrates its automated implementation using PowerFactory and Python. Where required, the methodology determines a preventive secure dispatch and generates contingency-dependent curative set points for GB operational planning. The results demonstrate that GB effectiveness strongly depends on the point of connection. A suitably located GB can enable secure operation under more constrained transmission capacity and reduce the preventive redispatch required to achieve N-1 security.

This paper assesses how the modelling of a large hydrogen electrolyser load affects the stability of an isolated, converter-dominated power system, using combined Root Mean Square (RMS) and Electromagnetic Transient (EMT) simulation. The objective is stability assessment at the pre-feasibility stage, where detailed equipment models are unavailable, with RMS results validated against higher-fidelity EMT simulations. The electrolyser characteristics a stability model must retain are identified and justified. Two representations are compared in a 100 % inverter-based modified IEEE 9-bus system: a simplified aggregated load model and a grid-following model of an active front-end interface. Simulations of generation outages and network contingencies address frequency stability, voltage response, synchronisation in weak grids and converter-driven oscillations, with control gains varied across scenarios. The assessed stability depends strongly on load representation, control tuning and electrolyser participation in ancillary services. The aggregated model yields optimistic results and omits the synchronisation loops and the voltage and frequency support of converter-interfaced demand. RMS modelling captures most of the dominant dynamics, which are confirmed by EMT, except for the fast converter interactions. Overall, coordinated inverter-level voltage and frequency support with electrolyser participation in frequency regulation proves the most robust configuration, and a basis for future isolated, inverter-dominated systems.

The rapid growth of wind and PV generation is increasing the utilisation of existing grid infrastructure and intensifying the need for operational solutions that enable higher integration without immediate grid reinforcement. Energy control automatic (ECA) systems raise the available transfer capacity by releasing grid reserves normally withheld for contingency situations to be used already in normal operation, while maintaining secure system operation. In contingency situations the system is designed to trip generation within milliseconds. Under operating conditions with high feed-in, such actions may alter power flows, reactive power balance, and voltage profiles in a dynamic manner. Since high inverter-based generation is often associated with reduced system strength, transient voltage stability is examined by extensive grid studies before such schemes are built and operated. This paper presents an RMS simulation study of a wind-dominated 110 kV German distribution grid incorporating an ECA system. The triggering instant, the contingency, an incorrect activation and the dispatch of an embedded High-Voltage-Direct-Current (HVDC) link are varied. In addition an overvoltage-driven cascade among plants without high-voltage ride-through capability is assessed. The results show, for the investigated scenarios, a transient overshoot to about 1.1 p.u. after fault clearing, while the curative disconnection adds about 0.01 p.u. for less than 40 ms. This voltage spike can be suppressed by varying the triggering time of the ECA. Potential cascades remain unlikely in the scenarios investigated. ECA operation therefore introduces no significantly increased transient stability risk beyond steady-state voltage considerations in the grid region. These findings support the secure use of ECA as an operational measure for the grid operator,

As the share of renewable, converter-based generators is rising and synchronous generators are phased out, grid-forming converters need to provide essential grid stabilising ancillary services.

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.

Demand-side flexibility is becoming increasingly important as power systems integrate more intermittent renewable generation and reduce reliance on centralized dispatchable units. In the residential sector, controllable resources such as Electric Vehicles (EVs) charging systems, Battery Energy Storage Systems (BESS), and electric water heaters can provide meaningful adjustment capability when coordinated within Renewable Energy Communities (RECs). This work compares two methodologies to quantify the technical flexibility of these resources under identical technical and economic conditions: a bottom-up (i) and a top-down (ii) approaches, requiring a consistent benchmarking under the same assumptions.

The Portuguese National Hydrogen Strategy, launched in 2020, relies on hydrogen produced via electrolysis using renewable electricity. It is currently under review, considering updated information and national goals. For producing renewable hydrogen and other derived renewable fuels of non-biological origin, many projects now being proposed or already being developed, rely on energy supply from the national electrical grid. However, it is shown that this approach is inadequate, especially for large scale projects. The optimisation of the renewable power mix for RFNBO production was addressed in the 2026 update of the 'carbon-neutrality in the energy sector by 2050' scenario (CN50), developed by the Directorate-General of Energy and Geology. Realistic power supply mixes were obtained that rely mostly on PV power, complemented with onshore and offshore wind power, and benefiting from otherwise curtailed energy from national electricity grid. Expected capacities for dedicated wind and solar power capacities for 2030 and beyond were obtained and related to exported hydrogen goals and national renewable energy share targets.

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.

With the ever-increasing share of Variable Renewable Energy (VRE) sources in the European energy mix, mitigating larger production forecast errors becomes increasingly challenging. In the long term, adequate reserves need to be planned and allocated accordingly to ensure grid stability. Therefore, accurately modeling weather-driven forecast uncertainties for renewable generation over long periods provides valuable insights for power system planning, market price projection, and adequacy assessment in Europe. Traditional long-term studies often rely on stochastic approaches to simulate forecast errors, which may not fully capture the underlying weather-driven spatiotemporal dependencies. Yet, simulating weather forecasts over long periods has become more accessible with the recent rise of AI-driven weather models in comparison to traditional approaches. This paper develops a methodology based on the Artificial Intelligence Forecasting System (AIFS) to simulate VRE day-ahead generation forecasts. Coupled with a methodology to convert weather variables into power generation (CorRES), wind forecast errors are simulated over multiple years from AIFS and aggregated at regional and country levels for Belgium and the Netherlands. Results are validated against observed forecast errors and compared to a previously established stochastic simulation approach for Belgium.

Offshore wind turbine harmonic models are increasingly required over wider frequency ranges, at finer frequency resolutions, and across more operating conditions. While these requirements aim to improve the reliability of grid studies, they do not necessarily ensure that a delivered model preserves the relevant converter behaviour or predicts quantities that are comparable with standardized power-quality measurements. This paper examines the construction and validation of frequency-domain wind turbine harmonic models from the perspective of the original equipment manufacturer.

The work combines field measurements, reprocessed emission records, analytical considerations, and high-fidelity software-in-the-loop studies using production-representative control software. Alternative methods for deriving the frequency-dependent turbine impedance and Norton-equivalent source are assessed, including analytical modelling, controlled simulation, and measurement-based identification. Particular attention is given to the distinction between the intrinsic Norton source and the measured terminal current, which also contains the turbine response to background voltage distortion.

Model validation is considered at three levels. First, impedance scans with different frequency grids are compared to determine when narrow-band control features are lost through coarse sampling or interpolation. Second, narrow-band model predictions are processed using equivalent spectral grouping, time aggregation, and percentile calculations to enable comparison with IEC 61400-21-1 power-quality reports. Third, the additional model fidelity required when extending the frequency range from 75–2500 Hz into the 0.1 Hz–9 kHz range is assessed, including low-frequency control coupling, sequence interactions, switching-related emissions, and measurement-bandwidth limitations.

The results demonstrate that model resolution, measurement resolution, and harmonic grouping are distinct concepts and should not be specified interchangeably. A 1 Hz model cannot be validated directly against grouped P95 measurements without applying a consistent measurement-equivalent observation process. The paper concludes that future TSO requirements should impose a transparent burden of validation while remaining method-neutral regarding model construction. Application-specific acceptance criteria, independent validation data, and automated quality checks can provide stronger confidence than prescriptive data density alone, while avoiding unnecessary modelling and disclosure burdens for manufacturers.

Europe’s transition to carbon neutrality requires coordinated policy alignment alongside significant changes in energy system planning and operation. The large-scale deployment of variable renewable energy sources (vRES), particularly wind and solar PV, is central to decarbonising the power sector; however, their inherent variability increases the need for system flexibility to maintain supply–demand balance.

In this context, the Man0EUvRE project under the EU Clean Energy Transition Partnership (CETP) developed different scenarios to explore alternative energy transition pathways. This work focuses on two contrasting scenarios, EU Trinity and NECP Essentials (NECP-E), modelled using the open-source GENeSYS-MOD energy system model, which optimises capacity expansion, generation portfolios, and flexibility requirements.

Building on the capacities obtained from GENeSYS-MOD for Portugal and Spain, this work analyses the operation and market participation of battery energy storage systems (BESS) in the Iberian day-ahead market (DAM). The DAM is simulated with the open-access PyMIBEL-DAM tool, based on the Python for Power System Analysis (PyPSA) framework. Two BESS operational approaches are compared: a system-optimal dispatch and a market-driven approach in which BESS participate as independent price-taking agents, optimising their charging and discharging schedules according to DAM price signals. The analysis considers 2030, 2040, and 2050.

Results show that the energy transition pathway and BESS operational strategy strongly influence future MIBEL outcomes. Average DAM prices decline towards 2050 as renewable penetration increases but remain higher under EU Trinity than under NECP-E, reflecting lower solar PV deployment and greater reliance on thermal generation. Solar PV captured prices also decline towards 2050 due to the price-cannibalisation effect, while onshore wind maintains higher and more stable captured prices. System-optimal BESS operation results in fewer demand non-covered hours, whereas market-driven operation generally increases wind and solar PV captured prices but may compromise system adequacy, particularly under EU Trinity. BESS arbitrage remuneration is strongly influenced by temporal price spreads and operational constraints, highlighting the role of operational strategy in determining storage value.

The findings emphasise the need to carefully plan the energy transition and design future electricity markets considering BESS operational behaviour, to promote the efficient integration of renewable generation while ensuring reliable system operation.

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.

Offshore Energy Hubs (OEHs) are emerging as a cornerstone for large-scale offshore wind integration, enabling multi-terminal HVDC transmission, cross-border power exchange, and enhanced operational flexibility. However, the high degree of converter-based generation introduces significant challenges during severe system disturbances. In particular, emergency events such as HVDC faults, converter blocking, or sudden transmission capacity constraints can lead to large and rapid increases in power imbalances that require coordinated, fast power reduction in connected offshore wind power plants (OWPPs).

As foreseen in Portuguese strategic documents such as the National Energy and Climate Plan 2030, industrial sectors must prepare their specific roadmaps to reach deep decarbonisation levels by 2050. In the past few years, the European Recovery and Resilience Program financed many decarbonisation roadmaps, including for cement, ceramics, glass, agroindustry, chemistry, textiles, machinery, plastics, wood products, and others.

As a part of the periodic efforts to update national-level plans such as the National Energy and Climate Plan 2030 and the National Strategy for Hydrogen, a high-level analysis was performed of these RRP decarbonisation roadmaps. While it must be recognized the high value of the roadmaps regarding each technical forecasts, eco-design, circularity, measures for actual processes, economic and financial issues, etc., the analysis focused only on energy-emissions.

In general, the roadmaps were found to be prioritise energy efficiency, electrification, and the phase-out of fossil fuels. In contrast, a wide range of views is presented regarding the role of biomass, of hydrogen and other renewable fuels of non-biological origin, and carbon sequestration. High level compliance has also been overlooked in some cases, for instance the amounts of biomethane and hydrogen foreseen were clearly overestimated considering the expected availability of these renewable gases at a national level.

However, an important finding relates to the interpretation of the meaning of ‘decarbonisation’ and therefore of the objectives of this type of roadmaps. Most roadmaps use emission scope up to 3 – in line with typical ESG assessments but downplaying emissions reduction of the sector itself. Therefore, many of the large emission drops featured in the roadmaps do not reflect decarbonisation efforts but rather the external context of national decarbonisation policies and measures. Apart from this, the industrial sector decarbonisation roadmaps were found to be in general alignment with the national level strategic documents.

As power grids rely more heavily on power electronics, grid codes now extend to fault ride-through, reactive power, and post-fault active power recovery requirements for demand facilities. However, national implementation varies significantly, requiring location-specific designs. This paper presents a case study for a 300 MW PtX facility examining how thyristor-based and IGBT-based rectifiers differ in grid code compliance. The requirements are assessed through power system simulations in DIgSILENT PowerFactory, covering steady-state, harmonic, and dynamic analyses.Thyristor-based rectifiers may require significantly larger passive filters to meet harmonic distortion limits. Multi-pulse configurations reduce harmonics but introduce operational constraints: harmonic cancellation requires balanced loading across all rectifier units, which is not achievable when individual units are offline for maintenance. Thyristor solutions may struggle with fast post-fault active power recovery requirements due to slow on-load tap changer voltage control. IGBT-based solutions achieve harmonic and fault ride-through compliance with reduced filtering needs. Technology selection is strongly governed by grid code dynamic response requirements, highlighting the importance of early-stage grid code assessment in PtX development.

As part of the energy transition, the share of converter‑based generation in the power system is rapidly increasing, while conventional generation is being phased out. This creates new challenges for maintaining system stability, in particular due to the loss of grid‑forming units and the reduction of the effective system strength . The German Federal Ministry for Economic Affairs’ “System Stability Roadmap” serves as a guideline for ensuring stable and robust system operation with 100% renewable energy and shows that the provision of grid‑forming capabilities in distribution networks must be enabled in the future.

Rapid electric-vehicle (EV) uptake in Kenya and comparable emerging markets is placing spatially concentrated loads on radial feeders that were not designed for them. A low-carbon national generation mix does not guarantee that an individual feeder has the voltage headroom to absorb clustered charging. This paper formulates charging-station siting and sizing as a constrained, mixed discrete–continuous, voltage-stability-aware planning problem and solves it using the artificial bee colony (ABC) algorithm with a backward–forward sweep load flow embedded in the fitness evaluation. A branch-based radial stability index that depends explicitly on active power is adopted and enforced as a constraint during the search, because the reactive-power-driven indices in common use respond only weakly to unity-power-factor charging. Uncoordinated and optimized deployments are compared on the IEEE 33-bus feeder at three penetration levels defined by installable charger counts, and EV hosting capacity is quantified under both statutory and operational voltage limits. Optimized siting reduces active-power losses by 30.3%, raises the minimum bus voltage by 0.0157 p.u. and increases hosting capacity by 247% relative to uncoordinated deployment, with results reported over 30 independent runs.

Robust power systems can generally accommodate large-scale renewable generation with limited stability impact; however, weak grids, such as those in rural areas or remote islands, remain vulnerable to severe transient disturbances. This paper presents a dynamic stability assessment of a remote island power system integrating an electrolyser facility with a wind power plant (WPP). Although steady-state operation is satisfactory, WPP tripping events cause severe disturbances that jeopardise secure grid operation despite the electrolyser's rapid ramp-down response. Synchronous condenser (SynCon) and battery energy storage system (BESS) technologies are evaluated individually and in hybrid configuration under partial and complete generation-loss scenarios. Baseline results confirm that acceptable steady-state performance does not ensure transient security. Immediately after the event, the electrolyser remains at its pre-event demand, requiring the grid to replace the lost generation instantaneously. The SynCon improves the initial transient response but requires substantial flywheel capacity to prevent frequency collapse. The BESS provides controllable active-power support but requires a considerable power rating when used alone. The hybrid SynCon-BESS configuration demonstrates complementary operation, where SynCon arrests the initial frequency decline, while BESS bridges the remaining load-reduction interval. Results demonstrate a practical approach supporting the stable integration of renewable generation and electrolysers in weak grids.

Due to increasing volatility and decentralisation of the generation, congestion management is becoming increasingly important for distribution grid operation. Therefore, accurate and reliable forecasts are essential for grid operators to maintain grid stability without expensive grid expansion or loss of safety and reliability. Existing approaches are either computationally expensive, have low temporal resolution, or do not quantify the uncertainty in the predictions caused by modelling or the forecast model itself. This study presents a comparison of two uncertainty-aware congestion forecast methods: a neural-network- and a Kalman filter-based approach. First, a PowerFactory-based grid model combined with a Monte Carlo approach is used to generate virtual power measurements. These serve as training data for a multi-layer perceptron, forecasting the expected value and quantiles of the power flows along lines and on transformers. Second, a graph-based abstraction is presented as the basis for a computationally efficient forecast relying on a Kalman filter. The comparison of both alternative methods focuses on the respective forecasting capabilities with respect to uncertainty quantification over variable time windows, as well as the data requirements during the modelling phase. The results demonstrate that both approaches have their merit in different application scenarios with varying requirements.

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.

Energy communities (ECs) support local decarbonisation, collective self-consumption and the integration of distributed energy resources (DERs). However, most EC planning methodologies size photovoltaic (PV) panels and battery energy storage systems (BESS) based on investment and operating costs, without accounting for participation in local flexibility markets (LFMs). Incorporating these potential revenues into the planning stage is challenging, since the flexibility that can be offered is measured against a baseline that depends on the DER capacities, making flexibility-aware sizing an endogenous problem. This paper proposes a genetic algorithm (GA)-based optimisation framework that jointly sizes PV and BESS capacities and contracted power while accounting for LFM participation. Each candidate solution is evaluated through operational simulations of baseline and flexibility-enabled operation. The framework is evaluated using a 10-member EC over a representative 30-day period, considering cross-sector DERs such as electric vehicles (EVs) and electric water heaters (EWHs). Results show that active cross-sector scheduling reduces BESS capacity by approximately 48%, increases offered flexibility by 18% and reduces TOTEX by 14% relative to an equivalent scenario non-controllable EVs and EWHs. These findings show that explicitly valuing cross-sector DER flexibility during planning changes the selected DER portfolio and improve the economic performance of the EC.

Fast electric vehicle (EV) charging stations often face limitations related to restricted grid connection capacity. To overcome these constraints, battery energy storage systems (BESS) are increasingly integrated to support charging demand while providing ancillary services such as peak shaving and energy arbitrage. However, most installations rely on monotype BESS solutions, which may not fully exploit the different power and energy requirements of these services. This paper investigates the use of a hybrid battery energy storage system (HBESS) combining high-energy (HE) and high-power (HP) battery technologies in a fast EV charging station. The study is based on a real charging station under development in Norway and considers realistic operating conditions, including measured charging demand profiles, electricity market prices, and local tariff structures. Three storage configurations are evaluated: (i) an HBESS composed of second-life NMC modules as the HE subsystem and LTO modules as the HP subsystem, (ii) a monotype BESS based solely on second-life NMC modules, and (iii) a monotype BESS based solely on LTO modules. The charging station operation is simulated in Matlab environment using coordinated energy management and power management strategies that simultaneously perform energy arbitrage and peak shaving. Technical and economic performance indicators, including electricity cost savings, peak demand reduction, grid utilization, losses, and payback time, are evaluated. The results provide insights into the potential benefits of HBESS solutions for future EV charging stations and support storage system sizing and planning in applications with both energy- and power-intensive requirements.

The rising share of converter-interfaced generation displaces synchronous machines and their grid stabilization characteristics. These leads to the increased need of grid-forming (GFM) converters unlike the today most common used grid-following (GFL) converters. Reliably distinguishing of the two control strategies purely on measurements at the point of connection remains challenging: prior studies offer either measurement-based classification without analytical depth or analytical references without experimental validation. This article closes that gap through an analytical space-vector evaluation of the voltage and current responses to defined grid voltage disturbances, validated by simulations and laboratory measurements across different GFM and GFL control structures. The analysis identifies an inherent decaying DC current component in GFM and ideal voltage source behaviour, which is not present in GFL or ideal current sources. It further exposes the limitations of fundamental-frequency analysis relative to time-domain assessment. The results show that within the first milliseconds of a disturbance, GFL and GFM behave fundamentally differently, and that the proposed space-vector based method enables robust, reliable classification for future testing procedures.

System stability for power systems with a high share of inverter-based renewables (IBRs) is a topic of much discussion. Experience of recent blackouts has highlighted two key characteristics, in addition to inertia, which are needed to ensure system stability:

• Ability to regulate voltage automatically,

• Ability to provide and tolerate high short-circuit currents during and after a fault.

Experience from the 2025 Spanish blackout has indicated that wind and solar power should contribute more than they historically have to the first characteristic. Grid-forming IBRs (presently being developed for wind turbines based on solar PV experience) can provide steady-state reactive power for voltage regulation, as can Type 5 wind turbines driving synchronous generators under AVR control. The reactive power capability depends on the active power being generated, which gives rise to a synergy between wind farms and solar PV, whose active power output is often inversely correlated. The second characteristic is more challenging for IBRs. The paper discusses a mechanical difference between wind turbines and solar PV systems which presents a fundamental barrier to cost-effective implementation of grid-forming IBR wind turbines. By contrast, the proven SyncWind Type 5 wind turbine power-train overcomes that barrier, providing a robust pathway to renewable grid stability.

Growing shares of variable renewables raise short-term price volatility and the value of assets able to revise their schedules close to delivery. This paper studies how a multi-unit pumped-storage plant hybridized with floating photovoltaics and battery storage should coordinate its participation across the day-ahead and intraday markets. A two-stage framework commits hourly schedules using a tractable head-dependent model of two coupled reservoirs, then re-dispatches at quarter-hourly resolution in a rolling horizon, holding the committed position by a two-sided settlement of the deviation and a penalty on departing from the planned water trajectory. In a 341-day case study of the Alqueva plant in Portugal, intraday participation raises profit by 8.2% without re-deciding the unit commitment. Valuing each resource directly shows the photovoltaic--hydro synergy to be almost entirely intraday, where the energy routed to the pumps grows thirteenfold over the day-ahead schedule, and the array captures 33% more per unit sold. Hybridization should therefore be evaluated across market stages.

This paper presents a detailed nonlinear state-space model of a grid-connected Renewable Power Plant (RPP) comprising multiple grid-following Power Generation Units (PGUs) interconnected through an internal collector network. The proposed modelling approach preserves the hierarchical PGU--String--Group--RPP structure while retaining the underlying electrical, control, and network states, thereby providing a physically meaningful representation of plant dynamics. A modular aggregation approach is used to represent parallel PGUs and Strings, enabling the model to be easily scaled to different plant configurations. The accuracy of the proposed complete nonlinear model is validated against a corresponding PSCAD electromagnetic transient (EMT) model by varying active and reactive power references. The results demonstrate close agreement in active power, reactive power, voltage magnitude, and voltage angle responses, demonstrating the model's ability to accurately capture the relevant dynamic behaviour of RPPs. The developed state-space model provides a unified foundation for small-signal stability analysis, eigenvalue and participation-factor analysis, controller design and tuning, model reduction, and the derivation of impedance/admittance representations for investigating converter–network interactions.

Residential PV Hosting Capacity Under High EV Adoption: A Swedish Low-Voltage Grid Study

Energy communities (ECs) can reduce energy costs and support local decarbonization by enabling consumers to collectively invest in distributed energy resources (DERs), such as photovoltaic (PV) systems and battery energy storage systems (BESS), and to share energy among themselves. However, sizing DER capacity becomes computationally challenging as the number of EC members and the planning horizon increase. Mixed-integer linear programming (MILP) algorithms can provide high-quality solutions but face scalability limitations. This paper proposes a hybrid MILP-Evolutionary Particle Swarm Optimization (EPSO) framework that combines the accuracy of deterministic optimization with the scalability of metaheuristic search. First, the MILP is solved over a reduced horizon to provide initial DER capacities. Then, this solution is used to initialize the EPSO population, which refines DER capacities over the entire planning horizon. Results show that the proposed framework achieves cost gaps below 1.6% compared to the full-horizon MILP optimum, while significantly improving scalability over an open-source MILP solver, making it a suitable alternative for larger ECs or longer planning horizons.

This paper investigates the frequency support capability of a grid-integrated, utility-scale hybrid power plant (HPP) comprising a wind power plant (WPP), solar power plant (SPP), and a battery energy storage system (BESS). The study focuses on the provision of ancillary frequency services, specifically frequency containment reserve and fast frequency reserve as defined by the market in the East Denmark bidding zone (DK2). The HPP is modeled in MATLAB/Simulink and Simscape and integrated into an IEEE 9-bus system, which is slightly modified to capture the desired characteristics of strong and weak grid conditions. In this modified IEEE 9-bus system, one of the generators is replaced by the HPP model to assess the grid frequency response to frequency disturbances. The simulation results show that, under weak grid conditions, the modified IEEE 9-bus system with only conventional generators provides more effective frequency support than the same system with one generator replaced by an HPP using grid-following control. To address this limitation of the HPP, a grid forming (GFM) control strategy is implemented to the BESS within the HPP. The results demonstrate that GFM control in the BESS significantly improves the HPP’s capability to support the grid frequency under weak grid conditions.

Electrification of transport and heat concentrates new stress in the distribution grid, while the same controllable assets constitute a flexibility resource. Activating that resource on a price signal alone, however, does not guarantee a feasible grid state, and the market-based procurement framework foreseen by §14c of the German Energy Industry Act is not yet operational. This paper presents the Orchestrator, an automated decision tool that evaluates standardised FlexOffers submitted by a neighbourhood from the perspective of a distribution system operator, weighing grid feasibility, established from an AC power flow of the CIGRE European medium-voltage benchmark network, against wholesale price, local peak shaving and renewable availability. The grid criterion uses feeder-specific warning thresholds and a materiality test, so that it responds to the effect of an activation rather than to upstream conditions. A low-voltage neighbourhood simulation and the medium-voltage grid calculation are coupled exclusively over MQTT. Over nine simulated months, 17.6 % of valid offers are accepted, with the two directions activated at systematically different times of day. Grid effects are measurable only in the immediate vicinity of the connection point, which quantifies the scale at which neighbourhood flexibility becomes visible to a medium-voltage feeder.

• 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.

Balancing supply and demand in national energy systems with an even higher share of renewable production is an important challenge and a major issue in prospective studies. This critical need for flexibility can be met by existing or new flexible productions, storage technologies like lithium batteries or by demand-side management. Regarding the environmental impacts of PV, focusing only on its carbon footprint during the phase of fabrication is not enough. A higher share of PV in the production requires additional flexibilities and network infrastructures. Unlike the carbon footprint of PV which focuses on the manufacturing stage, these impacts are systemic: they depend on its interactions with the broader electricity system and on how it evolves over time under a range of technological, economic, and societal assumptions. It is required to scenarize and model interactions with the whole electricity system to evaluate these impacts.

Grid-forming (GFM) inverters behave as voltage sources with an internal impedance. In the event of severe grid disturbances, this behaviour results in a high current response. Unless the inverter trips, this can lead to the destruction of the power semiconductors. Therefore, the implementation of a current-limiting method is essential to prevent tripping. One method is to use a virtual admittance to calculate virtual currents that can be limited an

To integrate offshore wind power, facilitate long-distance power transmission and interconnect asynchronous AC grids, HVDC systems are a crucial element of the European power system. While the majority of existing HVDC systems are designed as point-to-point (PtP) links, current grid development plans foresee a development towards multi-terminal HVDC (MTDC) systems. To protect such systems against DC-side faults, dedicated DC protection systems, typically based on DC circuit breakers (DCCBs) and current-limiting reactors, are required. The design of this protection equipment governs the converters’ dynamic behavior during DC-side and AC-side fault scenarios. Therefore, an adaptation of established PtP converter designs may be required to ensure compliance with fault-ride-through requirements. Previous research indicates that this can be achieved by increasing the number of submodules. However, existing research has not quantified how different degrees of freedom in HVDC system design translate into varying converter upscaling requirements, such as the required number of submodules.

Present-day Great Britain (GB) is largely reliant on thermal generation to enact electricity system restoration in the event of a national power outage. As Government policy and climate initiatives continue to the reshape GBs electricity generation mix at pace, the ability of low-carbon resources to deliver restoration services is critical to a resilient Net Zero power system. With offshore wind farms (OWFs) coming to dominate the generation capacity of the future GB system along with significant injection in battery energy storage (BESS), the complementary role of these technologies could be the key to enabling system restoration without thermal power plants.

Decarbonizing the transport sector through electric vehicles (EVs) requires understanding how EV charging affects the electricity system and how smart charging can support future energy systems. The aim of this study is to characterize the flexibility of smart charging by analyzing real world private EV usage patterns. The analysis is based on logging data collected from 394 privately owned EVs and survey responses from their owners. The results reveal substantial flexibility potential for smart charging. The share of EVs available for smart charging varies depending on the assumptions on to which extent they are connected for charging, ranging from about 20% to 90% during daytime on an average weekday. The average state of charge (SOC) during the entire logging period is 55% or higher for 95% of EVs. In weeks with more than three logged charging events, approximately 40% of the charging events could be eliminated, according to a mixed integer linear programming model that minimizes the weekly number of charging events while accounting for revealed SOC preferences. Furthermore, the electricity spot price leads EV owners with hourly electricity contracts to charge during hours with spot prices that are, on average 19% lower than those with non-hourly electricity contracts.

The transition toward deep decarbonisation relies heavily on sector coupling, proposing the use of existing natural gas networks to transport and store green hydrogen. However, hydrogen's low volumetric energy density poses a significant threat to the inherent thermal energy storage capacity of these infrastructures. This paper presents a fully dynamic, isothermal, one-dimensional transient partial differential equation model to quantify the thermodynamic, environmental, and economic impacts of hydrogen blending on the Portuguese high-pressure gas network. By simulating a 1278 km topology over a continuous 30-day horizon, this study investigates the linepack depletion paradox under two distinct injection scenarios: stochastic renewable curtailment and a dedicated continuous solar and wind power plant. Results indicate that blending at a nominal 70 bar inevitably induces a dynamic linepack deficit, reaching 10.85 GWh under continuous injection, critically limiting the flexibility buffer required by the wider energy system, while offering a negligible baseline CO₂ emission reduction of merely 0.05% to 0.50%. Furthermore, this study mathematically disproves the viability of elevating network baseline pressures to recover storage capacity. Boosting the operational pressure to 80 bar successfully restores the lost thermal inertia but triggers a severe environmental backfire, actively increasing CO₂ emissions by up to 0.44% due to the forced injection of compensatory fossil gas. Economically, this high-pressure recovery regime imposes a highly non-linear penalty on the grid, surging compressor electrical power demand by up to 36.18%. Consequently, the Levelised Cost of Hydrogen for curtailment escalates to an unfeasible value exceeding 12 €/kg.

The global commitment to reduce carbon emissions and build a more sustainable society relies on the transition towards highly interconnected power grids which connect a wide variety of renewable sources, storage facilities and consumers via innovative converter-based energy links. Concerning ac distribution, medium voltage static frequency converters (SFC) assure a seamless connection between sources/utilities, while optimizing the transmission frequency and voltage levels as well as providing primary/ancillary services that enhance grid resilience and system stability. Therefore, such grid intertie achieved through SFCs is a technology enabler to establish an efficient and flexible electrical infrastructure. For instance, connecting offshore equipment with a landfall point through sub-sea cables significantly increase the attractiveness of those remote areas where large offshore wind farms might be built. A loss-optimized energy link with shore serves as a collector for multiple interconnected units, opening-up to several climate response initiatives and enhanced economical assets for the site owner(s). Interestingly, most of the European offshore wind parks (in operation or committed) are in the 100–300 km distance range with power ratings of 40–200 MW. For these installations within a mid-to-long distance range, a grid intertie based on a low frequency high voltage alternate current (LF-HVAC) transmission framework represents a cost-effective solution compared to other alternatives. A transmission frequency below 20Hz reduces both the charging current and the reactive power on the cable, thereby requiring smaller size reactive power compensators, i.e., lowering the installation cost. Due to the different frequency range that offshore wind parks could exhibit compared to the one characterizing the onshore grid, the LF-HVAC transmission is established with a dual SFC configuration. The onshore SFC station—primary interface to the main grid—is operated such that the power exchange along the ac cable is realized at, e.g., 16.7Hz, while the offshore SFC station—main connection point to the generation site—converts it back to the required ones. The fluctuations of the generation units may lead to experience low short-circuit ratio at the SFC terminals, particularly critical during contingency events. Moreover, in case of an onshore grid showcasing lack of inertia, the entire system is prone to instability. Nevertheless, both aspects can be mitigated by the enhanced controllability given by the proposed grid intertie scheme, further extending its installation benefits. Motivated by the above, this paper will describe such dual SFC configuration currently offered by Hitachi Energy, targeting the above-mentioned application. To demonstrate the advantages of the proposed solutions, comprehensive simulations at steady-state and during transient operations are presented, along with the ability to ride through the most relevant fault scenarios.

This paper addresses the challenge of forecasting electricity consumption time series at a regional aggregation level. Due to limited measurement data and the lack of reliable validation benchmarks, generating accurate day-ahead forecasts for small geographic units remains difficult. The study focuses on overcoming these limitations by combining national-level forecasting with regional disaggregation approaches. In this way, it supports improved power system analysis and operation, particularly for grid calculation and stability assessment.

This paper investigates the technical feasibility and safety of utilizing Vehicle-to-Grid (V2G) technology for 3-phase island operation and backup power. While modern electric vehicles (EVs) are increasingly V2G-capable, their onboard converters can typically only power single-phase loads and DC bidirectional chargers are typically grid-following and require an external battery and grid-forming inverter to establish a reference voltage during blackouts. The study evaluates several common European hybrid PV–battery systems to determine their ability to support V2G in micro-grids. The tests were conducted in the laboratory of the University of Gävle as part of a pilot with 250 V2G chargers of which 50 chargers are dedicated to DSOs to utilise their own EV cars for grid support, including backup power. A target was to derive the smallest external power from batery and grid forming inverter required to allow the projects 11 kW V2G grid-following chargers to operate. Key focus areas of the tests include power quality, potential converter-driven instability, and electrical safety. A critical component of the testing involves verifying automatic shutdown procedures during the loss of earth connection. The findings aim to establish whether V2G can provide a reliable, cost-effective, and low-emission alternative to diesel generators for community emergency assistant points and private residences during prolonged crises.

The growing penetration of variable renewable energy sources (vRES) and electrification-driven demand is increasing the volatility of real-time system operation, highlighting the need for early-warning tools to anticipate periods of stressed balancing. This work proposes a data-driven framework to forecast upward and downward manual frequency restoration reserve (mFRR) activation events in the Portuguese power system using five alert levels, from Level 1 to Level 5 (most critical), defined from historical data to provide a progressive and operationally meaningful characterisation of reserve stress. mFRR activation is predicted using a machine-learning classifier.

Results indicate that wind power forecast deviations are the dominant driver of mFRR activation. Detection precision increases from nearly 50% for the most critical events (Level 5) to nearly 80% for less critical levels. Upward activation is strongly dependent on forecast horizon, with better performance closer to real-time operation, while downward activation shows similar performance for all horizons analysed. Overall, the framework can complement existing deterministic forecasting and operational tools by enabling earlier assessment of system conditions and supporting adaptive reserve allocation in increasingly vRES-dominated systems.

The increasing penetration of converter-interfaced generation creates new opportunities for offshore wind farms to contribute to power system restoration. Grid-forming (GFM) control can enable offshore wind turbines to establish and regulate an islanded network; however, the proportion and electrical placement of GFM capability required for successful restoration remain important design considerations. This paper investigates the influence of GFM penetration and placement on the restoration capability of an HVAC-connected offshore wind farm comprising Type-4 wind turbines. A detailed time-domain simulation model is used in which an onshore GFM battery energy storage system initially energises the transmission infrastructure and offshore network. Following establishment of the first offshore GFM wind turbine group, the battery is disconnected and restoration proceeds using the offshore wind farm, with the remaining wind turbine groups progressively brought into operation using different combinations of GFM and grid-following control. GFM penetration levels from 25% to 100% are investigated, together with alternative electrical placements at selected penetration levels. Restoration performance is assessed using voltage and frequency deviations, rate of change of frequency, and active- and reactive-power responses. The results demonstrate that the proportion and distribution of GFM capability have a significant influence on the dynamic behaviour of the offshore island and show that full GFM conversion is not necessarily required to support wind-farm-led restoration. The study provides a framework for identifying suitable GFM penetration and placement for offshore wind power system restoration.

Grid-forming units are expected to provide voltage-source behavior and frequency-related active power support in converter-dominated power systems. In Germany, the VDE FNN guideline on grid-forming capabilities defines measurement-based verification procedures in fictitious island operation, in particular for voltage-source behavior and grid-security-based primary control (PRNB). While these tests are highly relevant for the qualification of grid-forming units, their conventional realization requires a comparatively complex laboratory setup with dedicated hardware and limited flexibility.

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.

Atlantic ports are evolving into energy hubs in which wind, photovoltaic, marine and hydrogen technologies are integrated into electrical grids not originally designed for them, while enabling opportunities of new energy markets within port boundaries. The deployment of these technologies requires both suitable technological solutions and regulatory-legislative frameworks that enable their effective integration into ports’ power systems. This paper partly condenses results of the ENEPORTS project (Interreg Atlantic Area) into a practice-oriented methodology that port authorities and operators can follow when planning renewable hybrid systems. The methodology covers grid access, grid codes, feasibility studies, power quality assessment, protection systems’ coordination, market models, grid-integration challenges and operational considerations such as digitalisation, energy management systems (EMS), flexibility and internal energy markets. Data from current and projected demands of three port areas were used to model and study the feasibility and operational conditions of these hybrid systems, complemented by an analysis of case studies from other European ports. The methodology has been validated with real port ecosystems in Ferrol–San Cibrao, Granadilla and Douro–Leixões. The results provide a reusable roadmap to accelerate renewable hybrid system deployment while safeguarding grid stability and power supply quality in port areas.

Poorly damped natural subsynchronous oscillations in IBR-dominated power systems may emerge or disappear as operating conditions change, requiring stability assessment tools capable of tracking the corresponding system dynamics. This becomes particularly challenging for black-box IBRs, whose dynamic responses vary with the operating point and must be efficiently updated for near-real-time assessment. This paper presents a frequency-domain digital twin (DT) framework to address this challenge. The proposed modular bottom-up approach characterises IBR dynamics offline through dynamic frequency scans across their operating range. Parametric frequency-response models are then evaluated at the prevailing operating point and interconnected with the rest of the system representation to reconstruct the overall system dynamics. The resulting DT enables tracking of critical oscillatory modes and provides early warning of emerging poorly damped operating conditions. The framework is demonstrated on a modified IEEE 39-bus system, showing its ability to capture the evolution of critical modes as the operating point changes. Computational scalability is further assessed using modified IEEE 118- and 300-bus systems, quantifying the reconstruction requirements as system size and number of IBRs increase. Overall, the proposed framework provides a scalable basis for broader stability assessment applications while accounting for operating-point-dependent dynamics.

Rapid reductions in electricity demand caused by synchronised AI-computing activity may produce over-frequency disturbances, particularly in low-inertia power systems. This paper proposes a two-stage stability-constrained unit commitment (UC) framework that coordinates power-system operation with data-centre (DC) flexibility through a grid-facing import-cap interface. Unlike task-level scheduling models, this approach requires no information about workload arrivals, latency tolerances, or service priorities and is therefore applicable to system operators and facilities with limited workload visibility. Stage I formulates a mixed-integer second-order cone programme co-optimising generation, reserves, inverter-based frequency support, and hourly DC import limits to secure against both under-frequency (generator loss) and over-frequency (DC demand reduction) events. Stage II then assesses each hourly schedule through simplified nonlinear AC redispatch. In the 65-MW low-renewable case, coordination replaces 2.394 MWh of involuntary shedding with contracted import limitation. Under the assumed flexibility price and shedding penalty, the total penalised objective decreases from £282.84k/day to £247.40k/day. The results illustrate how non-firm connection agreements can improve frequency security and connection capability while leaving internal workload control to the DC operator.

The transition of power systems toward higher shares of Inverter-Based Resources (IBRs) is reshaping the technical needs of the power system, fragmenting the naturally bundled portfolio historically provided by synchronous generators (SGs) and presenting spatial and temporal interactions between system needs and services. Understanding these couplings is important for determining how system services should be coordinated and delivered under different operating conditions. This paper presents a data-driven framework for identifying and quantifying dynamic couplings between power system needs using measured output trajectories. A windowed stochastic subspace identification method is used to obtain a dynamic representation of the system, from which trajectory sensitivities are derived to characterise interactions between active power, reactive power, frequency, and voltage across network locations. The framework is demonstrated on modified IEEE 14-bus systems representing synchronous-generator-dominated and IBR-penetrated operating conditions. Results show that the magnitude, direction, location, and duration of system couplings vary significantly with network composition. In particular, active- and reactive-power support can both influence frequency, with these interactions becoming increasingly spatially and temporally dependent under IBR penetration. The proposed framework provides a technology-agnostic basis for identifying critical service interactions and informing coordinated power system service delivery.

The integration of small-scale, distributed flexibility, such as electric vehicles (EVs), is becoming increasingly relevant for market-based system operation and redispatch-oriented applications. In this context, operators need both robust ex-ante estimates of feasible flexibility and operational checks of whether planned and realized behavior remains technically plausible. At the same time, available charging field data are often sparse and only partially observable, which limits direct transfer of historical patterns to changing market conditions, weather, calendar effects, user-group composition, and incentive structures.

This paper presents a hybrid workflow that combines measured charging data with stochastic driving-and-charging simulation. The approach maps field observations to a compact set of effective flexibility parameters and embeds them into a scenario-ready model chain. Key behavioral and technical drivers, including plug-in behavior, connection duration, charging power limits, state-of-charge constraints, calendar-related usage patterns, user-group characteristics, and incentive-related charging responses, are represented to derive context-specific flexibility envelopes.

These envelopes are used as an extended measurement layer for market analysis and can support forecasting and redispatch-related monitoring. In particular, they can support near-real-time plausibility checks of offered or scheduled flexibility and post-event assessment of dispatch outcomes against technically feasible ranges.

The presented results indicate that this physically grounded representation improves transparency and consistency when assessing decentralized EV flexibility under data scarcity. The framework therefore provides a practical basis for linking ex-ante flexibility estimation with operational monitoring in evolving market-based grid applications.

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.

Technical advances in high-performance wind turbine generators (WTGs) are driving increasingly demanding requirements for their power converters, particularly in Type 4 WTGs, where the full generator power is fed into the grid via power converters. From a power electronics perspective, WTGs represent a high-power, low-voltage application, resulting in relatively high current requirements. Due to the limited current-carrying capability of individual power semiconductors, the desired output power is typically achieved by using multiple parallel power converters. While such architectures improve scalability, they also introduce internal interactions between the parallel power converters in the form of circulating currents, which are not explicitly addressed by conventional current control schemes.

The integration of Distributed Energy Resources (DERs) into modern power systems is often limited by heterogeneous communication protocols and manufacturer-specific data representations. This paper presents DERway, an edge interoperability gateway that provides bidirectional communication between DER devices and grid-facing applications. DERway supports southbound protocols including Modbus TCP/IP, Modbus RTU, and CAN, while exposing telemetry and control capabilities through MQTT and REST interfaces. The gateway follows a modular architecture in which device-specific communication and data transformations are decoupled from upper-layer modules through an \textit{Internal MQTT Broker}. Device integration is primarily configuration-based, with scripting support for manufacturer-specific decoding and transformations. DERway is experimentally validated in X-Energy Lab, a reconfigurable smart-grid laboratory from INESC TEC, against four real DER devices spanning all three supported field protocols: two batteries over Modbus TCP/IP, a heat pump over Modbus RTU, and a DC-DC EV charger over CAN. The results show that the same architecture sustains weeks-long telemetry acquisition with over 99\% reading delivery and confirms bidirectional setpoint control within a few polling cycles, without protocol-specific changes outside each device's own configuration, demonstrating the feasibility of a common edge gateway architecture for heterogeneous DER communication.

The increasing penetration of distributed energy resources in modern power systems is intensifying operational challenges related to voltage regulation, particularly in low-voltage networks with heterogeneous assets, limited observability, and strong local coupling between controllable resources. Although centralised optimisation approaches can coordinate corrective actions across multiple devices, they typically require continuous communication with a supervisory controller, full disclosure of local operational data, and increasing computational and communication effort as the number of controllable assets grows. This paper presents DERway as a distributed edge-computing platform designed to support cooperative voltage control through the coordinated execution of a distributed optimisation algorithm across multiple smart gateways. In the proposed approach, each DERway gateway is deployed close to a subset of local DER assets and executes an ADMM-based control routine using local measurements, local constraints, and limited exchanged variables. Rather than relying on a fully centralised decision layer, the gateways cooperate iteratively to converge towards a coordinated solution that mitigates voltage violations while preserving the decentralised nature of control. DERway provides the practical execution environment for this distributed coordination through modular local services, device-level communication interfaces, internal data handling, and edge-side processing capabilities. The platform supports acquisition of local measurements, execution of the optimisation routine, and exchange of coordination variables between gateways, enabling distributed control to be deployed close to the physical assets. The proposed framework was evaluated in a smart-grid control context involving multiple cooperating gateways and voltage-regulation scenarios with distributed controllable resources. The results show that the distributed edge-based approach can successfully mitigate voltage violations through coordinated local decision-making, while reducing dependence on centralised control and avoiding the need to disclose full local datasets to a single supervisory entity. The work therefore demonstrates that smart DER gateways can evolve beyond interoperability functions and act as edge-native optimisation nodes for scalable and privacy-aware operation of distributed energy systems.

This paper evaluates negative-sequence voltage control for grid-forming converters under asymmetrical faults. Six control methods based on vector voltage control with virtual impedance and virtual admittance control are compared in terms of control objectives, small-signal stability, and parameter tuning complexity. It is found that the direct implementation of virtual impedance or virtual admittance may cause small-signal instability due to insufficient damping. Stable operation can be achieved by introducing an LPF, modifying the virtual-impedance feedback structure, or adding virtual resistance with an HPF. Among the evaluated methods, virtual admittance control with proper damping provides stable operation with lower parameter tuning complexity and is identified as the optimal control solution for negative-sequence voltage control.

In this paper, we investigate a recently proposed neural network method for learning the input-output behavior of power system devices using field or simulation data. This method adapts Neural Ordinary Differential Equations to represent components described by differential-algebraic equations, which are essential in power system component modeling. The approach yields continuous-time state-space models that can be seamlessly integrated into existing transient stability simulation tools. We utilize this method to train surrogate models using data obtained from transient stability simulations of a standard inverter model. We evaluate the performance of these surrogate models and analyze how their accuracy depends on neural network architecture and training parameters, such as the volume of required data. Furthermore, we assess the model’s ability to represent various transient behaviors, including responses to active and reactive power commands and low-voltage ride-through events.

Gigawatt-scale hybrid wind and battery energy storage system (BESS) plants are increasingly being deployed in weak, inverter-dominated networks where compliance with stringent grid-code requirements must be maintained across a wide range of operating conditions. While much of the existing grid-forming (GFM) literature focuses on inverter-level control behaviour, the dynamic performance of large hybrid plants is also strongly influenced by plant topology, electrical distance between generating assets and the point of connection (PoC), and the coordination of plant-level control functions.

This paper presents a plant-level coordination framework for a hybrid wind and GFM BESS power plant in which a centralized GFM BESS is integrated with grid-following (GFL) wind turbine generators (WTGs) through multiple power plant controllers (PPCs) operating at a common PoC. Particular focus is placed on the allocation of reactive-power duty between the wind farm and BESS subsystems and on the coordination of on-load tap changer (OLTC) target voltages.

The proposed architecture is evaluated using electromagnetic transient (EMT) simulations of a gigawatt-scale hybrid project connected to a weak grid. Performance is assessed against key Australian National Electricity Rules (NER) requirements, including disturbance ride-through, continuous uninterrupted operation, and system-strength capability. The results demonstrate that shifting reactive-power responsibility from the wind farm to the electrically closer BESS reduces wind-turbine terminal-voltage excursions and mitigates DC-link overvoltage tripping during fault clearance. Furthermore, coordinated adjustment of reactive-power sharing and OLTC target voltage enables successful ride-through under both reactive-power export and absorption extremes. Additional studies at progressively lower SCR conditions show that stable post-fault recovery can be restored by reducing wind-turbine fault reactive-current contribution, while the centralized GFM BESS maintains a well-damped response.

The findings indicate that reactive-power allocation and OLTC settings should be jointly optimized across the plant operating envelope rather than assigned solely in proportion to installed capacity. The proposed plant-level approach provides a practical pathway to weak-grid compliance for giga-scale hybrid plants.

As power systems transition toward inverter-based resources (IBR)-dominated grids, Grid-ForMing (GFM) IBRs are increasingly expected to provide the voltage-source characteristics required to maintain adequate system strength. However, the quantification of how much GFM capability is required and where it should be located in the grid remains unclear. This paper investigates the impact of the amount and location of GFM IBRs on small-signal system strength. The Jacobian Voltage Stiffness Metric (JVSM), which quantifies the voltage-magnitude and voltage-phase stiffness of the grid from its frequency-domain Jacobian characteristics, is used as a bus-wise system-strength measure. Unlike existing metrics, JVSM captures the relevant frequency-dependent dynamics at each grid location without assuming ideal voltage-source behaviour or requiring detailed models, reference impedances, or computationally intensive, error-prone eigenvalue or singular-value analyses. The impact of GFM provision is systematically assessed by varying the number and location of GFM IBRs in the grid. The analysis on a modified IEEE 39-bus system demonstrates that increasing the number of GFM IBRs generally improves system strength; however, JVSM quantifies variations in bus-wise system strength and characterises their dependence on GFM location, with the strength assessments validated through small-signal modal analysis. The results show that specifying GFM requirements solely in terms of penetration level or installed capacity may not adequately characterise the resulting system strength. This quantification provides a basis for the future development of GFM requirements that account for both the amount and location of GFM capability.

Background and objective

Under the intermittency of renewable energy and other fluctuation of demand and supply sources, we need a variety of energy storage system (ESS) of different specifications to keep a secured and stable operation of a power system. The needs to balance demand and supply vary according to characteristics of fluctuation and we need to find the optimum alternatives of ESS specification of the storage technology which most fits to the needs of a power system.

In this study, we analyze the impact on operational cost under different scenarios of generation, flexibility supply from traditional generators, distributed generators, demand responses and ESSs in Japan in 2040.

Methods used

The method used is a production cost analysis tool “MR” with network constraints using real demand and supply condition of the future power system of Japan.

MR, through daily optimization, has a capability to set the requirement for different flexibilities and to define supply capability of various sources including traditional generation and distributed resources to optimize the generation dispatch, flexibility dispatch and demand shift to minimize the operational cost.

MR-LP is a linealized MR, for fast calculation of multi-day optimization.

Main results obtained

In the simulation, we first use a linearized production cost analysis, one of a functions of MR to analyze a more-than-one-day production of a power system to decide a SoC of an energy storage at the end of a day, and secondly, we analyze daily production simulation to make the detailed evaluation of the system operation. For the analysis, we estimate the several demand and supply scenarios of a power system in Japan in 2040. The scenarios are set according to the 7th Strategic Energy Plan of Japan, OCCTO scenario, and publicly available data. We also estimate the future requirements for flexibilities (FCR, S-FRR, FRR, RR, and RR-FIT) dependent on the capacity of vRES and demand level.

The results of the production cost analysis will show the followings:

For seconds-to-minutes fluctuation, ESS supply the balancing service in cooperation with traditional generators.

For minutes-to-hourly fluctuation, ESS supply the balancing service in cooperation with traditional generators, demand-side technologies and demand response.

For hourly-to-daily fluctuation, we have options of batteries, pumped hydro systems, and other LDES technologies.

The combined requirements for flexibilities have a critical impact on the cost of system operation to affect the selection of ESSs in a power system.

The implications from the analysis results are:

It is essential to combined the energy storage technologies of different characteristics and specifications for the future power system.

It is critical to establish process to decide the specification of ESSs.

LCOS can be calcurated based on the production cost simulation for different demand supply condition of a power system.

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.

The idea of this paper is to open the discussion of how we can bring energy to the EV charging stations, especially in remote areas and near to highways where the medium voltage is not available nearby or needs to be upgraded to supply the power needed from the EV charging stations.

The energy transition is accelerating the deployment of large-scale hydrogen electrolysis plants to support the decarbonization of hard-to-abate sectors such as steel, chemicals and e-fuels. As hydrogen developers increasingly require power system studies to optimize electrical designs and demonstrate grid-code compliance, accurate dynamic models of electrolyzer rectifier systems have become essential. This need is further reinforced by the growing interest in partially or fully off-grid configurations coupled with renewable energy sources, where weak-grid conditions may pose significant stability challenges. This paper presents a detailed electromagnetic transient (EMT) model of a 20 MW alkaline electrolyzer supplied through a multi-winding transformer and a thyristor-based rectifier. Developed in a MATLAB-based environment, the model includes transformer topology, rectifier behaviour, electrolyzer electrical characteristics, and control systems. Based on the EMT reference model, a Root Mean Square (RMS) representation suitable for large-scale power system studies is proposed and implemented in PSSE. A comparison between EMT and RMS simulations shows that the proposed RMS representation reproduces the main steady-state and dynamic trends of the EMT reference model within the investigated operating range.

Hydrogen plants based on water electrolysis are expected to play a key role in the decarbonisation of industry and the integration of renewable energy sources. Since electrolyzers operate with DC current, large rectifier systems are required to interface with AC networks. These rectifiers, typically based on thyristors or IGBTs, inject harmonic currents that may significantly affect power quality, particularly in large-scale installations with hundreds of megawatts of electrolyzer capacity. While the harmonic behaviour of individual converters is well documented, there is currently no widely accepted methodology for assessing the cumulative impact of large hydrogen plants on electrical networks. This paper analyses the harmonic interactions produced by multiple electrolyzer rectifiers, with particular focus on harmonic phase-angle coherency, transformer phase-shift cancellation strategies and the limitations of conventional harmonic aggregation methods. The study also evaluates the implications of passive filtering solutions, including resonance effects and filter sizing requirements in large industrial facilities. The work supports the development of more reliable grid integration studies for large-scale hydrogen plants connected to renewable-dominated power systems.

Rapidly disseminating renewable generation and worldwide transition into decarbonized power plants has triggered drastic transformations in the types and operations of new generation power systems within present electricity grids. Considering the thermal energy production sector of a country like Angola where thermal power generation still dominates, the continuous decommissioning of these units should be examined scientifically to make sure the system stability and reliability. The current study investigates the impact of plant decommissioning in the thermal power sector on power system stability and decarbonization in Huíla Province as a case study. With PSS®E, a simulation-based analysis is designed under various scenarios of the integration of renewable energy when thermal generation is gradually reduced. Among various stability indices that should be taken into account in analyzing the picture: voltage stability, system losses, and frequency response dynamics. There are three operating scenarios in question: (i) the thermal dominated system, (ii) the hybrid system with moderate renewable penetration and (iii) the high-renewable penetration system supported by decentralized generation. The results demonstrate that high renewable energy penetration is statistically associated with a significant improvement in both system efficiency and reduced greenhouse gas emissions, up to 70% for high renewable energy scenario. However, there are problems related to low inertia and voltage stability of the systems especially at high displacement of synchronous generation. The combination of phased decommissioning, adequate grid reinforcement and planned renewables integration is essential in achieving environmental sustainability and operational security. The results of this study will be useful to energy planners and system operators that aim to formulate coherent transitions pathways for power generation systems of the future like that in Angola.

This work presents a novel, physically based RMS model of a large-scale electrolyzer, developed to be used in power system

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.

The grid-, market- and system-supportive use of decentralised electricity storage systems and electric vehicles with bidirectional charging requires suitable regulatory conditions. The MiSpeL Pauschaloption developed by the German Federal Network Agency is intended to enable the mixed charging of storage systems with PV electricity and electricity from the grid, followed by feed-in to the public grid. This paper uses an optimisation-based simulation model to analyse the effects of the 2025 Consultation Draft and the Revised Working Version 2026 on different prosumer configurations with stationary battery storage systems and/or bidirectional charging infrastructure with an associated electric vehicle. The results show that, in cases with high PV surplus feed-in, the original consultation draft can create financial benefits solely by changing the accounting concept, without storing electricity from the grid and feeding it back into the grid. This creates a false incentive, as financial relief can occur without the market- and grid-supportive storage operation that the regulation is intended to promote. The indifference range introduced in the Revised Working Version 2026 of the Pauschaloption significantly reduces this effect. At the same time, however, it increases the offsetting threshold and therefore the barrier to the economically viable intermediate storage of electricity from the grid. As a result, actual storage of grid electricity followed by feed-in back to the grid is economically used in only a few of the analysed configurations. For electric vehicles with bidirectional charging, the largest additional potential mainly results from the time-shifted feed-in of PV electricity and reaches up to around EUR 600 per year in the analysed cases. Overall, the results show that the fixed remuneration limit of 500 kWh/kWp and the indifference range can only partly reflect different consumption levels, self-consumption patterns and system configurations.

Industrial process heat dominates manufacturing emissions in the EU. Yet, there are readily available solutions that can continuously generate process heat. Industrial heat pumps and heat batteries paired with on-site solar PV can be a solution to bring power to heat generation quickly and cost competitively with natural gas. Using a dataset of 2,192 facilities of different manufacturing sectors from Climate TRACE, each facility is modelled with co-located, off-grid solar PV with industrial heat pumps and batteries installed in 2030. Under this modelled configuration, 58.8% of fossil-fuelled process heat can be decarbonised using solar PV within a 5 km buffer zone around each facility site at an average levelised cost of heat of €55/MWh. After expanding the buffer zone to 15 km, the share of possible decarbonised heat rises to 84.4% of process heat at €62/MWh against an EU average gas-heat cost of €93/MWh. Each facility is optimised to provide the highest availability and highest savings under its country's gas costs. These results show that Southern Europe can cost-competitively decarbonise over 95% of its heat demand. Central Europe (Rhine-Meuse Region), where most of the large, heat intensive sources are located, can decarbonise over 70% of its heat demand using on-site solar plus storage.

This paper reviews methods of calculating Critical Clearing Time (CCT) in power systems. Most existing CCT studies focus on power systems dominated by Synchronous Generators (SGs). In contrast, the impact of Synchronous Condensers (SCs) on CCT in modern power systems remains less explored. SCs are increasingly deployed to provide system strength and to support higher penetration of inverter-based resources (IBRs). In the Australian power system industry, system strength refers to the ability of power systems to maintain a stable voltage waveform both in normal operation and following disturbances. This paper compares the CCT of a SC and a SG of equivalent rating using a simplified single machine infinite bus model. The simplified framework enables a direct comparison without the confounding effects of additional system complexity. The study also investigates the influence of the inertia constant of SCs and SGs on CCT. It is widely assumed that the additional inertia provided by SCs enhances system stability as SGs are progressively displaced by IBRs. The provision of system strength by SCs decouples their operation from system loading, hence future systems may exhibit comparatively high inertia levels during light-load periods. This likely alters oscillatory behaviour and damping in the future power system.

Grid congestion is today relieved mainly by redispatch, one of the main drivers of grid operation cost. Busbar switching allows transmission system operators (TSOs) to reconfigure substation connectivity and redistribute power flows without redispatching generation, but systematically optimizing busbar configurations across large transmission grids remains an open problem, particularly for integration into operational TSO processes.

Existing solution methods, including mathematical optimization and exact enumeration approaches, predominantly evaluate candidate topologies with a linearized DC power flow, sacrificing voltage accuracy and reactive power modeling. This approximation is most consequential in voltage-sensitive, high reactive-power operating conditions. Genetic algorithms (GAs) are not subject to this limitation, as they handle discrete switching variables natively and place no restriction on the fitness function, allowing evaluation by a full AC power flow.

We investigate GA setups for AC-exact transmission topology optimization (TTO), in which every candidate topology is evaluated with an AC power flow. TTO is formulated as a multi-time-step problem, so that temporal coupling between switching actions is part of the search itself. On top of a baseline AC-exact GA, we examine a distance-biased mutation scheme that redistributes mutation probability toward switches electrically close to congested lines, and elitism and skip-bad-individual rules that reduce the number of power flow evaluations. To address the computational cost of AC evaluation at scale, we further examine three mixed-fidelity acceleration schemes that combine cheap DC pre-selection with AC power flow validation: a one-shot switch from DC to AC evaluation, a periodic DC/AC switching cadence, and an AC archive that tracks top-ranked, AC-verified individuals alongside a DC-evaluated population.

The setups are benchmarked on the IEEE case118 and case2869pegase grid models, expanded into double-busbar substations, over multi-time-step congestion windows constructed to test both stationary and moving congestion patterns. Setups are compared under an equal wall-clock budget, using feasibility rate, number of switching actions, worst-case loading and voltage margins, and runtime and power-flow-evaluation counts as KPIs. This provides a first systematic evaluation of AC-exact GA search for busbar-based congestion management across multiple time steps and realistic grid sizes, and practical guidance on the trade-off between DC-accelerated throughput and AC-exact solution quality for TSOs seeking to deploy automated topology optimization at scale.

Analyzing industrial flexibility participation in Day-ahead and Intra-day markets of Nordic Countries: Electrified Asphalt Production Process as an example case

Achieving a fully decarbonised power system by 2050, if not earlier, implies unprecedented penetration levels of variable renewable energy sources (vRES). In several mature markets, however, investment momentum is slowing as vRES projects transition from public-subsidised remuneration schemes to full merchant or quasi-merchant exposure. Current market arrangements—optimised historically for dispatchable thermal fleets—are increasingly misaligned against the operational and risk characteristics of non-dispatchable, low-marginal-cost generation.

This paper investigates protection coordination for a 100% grid-forming offshore wind farm connected to a diode rectifier unit (DRU) HVDC link supplying a large load plant. The fault response of the grid-forming wind-turbine converters and the associated offshore protection requirements are analysed. A layered protection scheme combining overcurrent, directional overcurrent, and line-current differential functions is proposed to detect and selectively isolate short-circuit faults in the offshore collector network. Electromagnetic-transient simulations in PSCAD demonstrate converter fault-current limitation, string-level fault isolation using directional overcurrent protection, and cable-section-level isolation using line-current differential protection. A hydrogen electroiysis plant is used as the case study; however, the proposed protection principles are independent of the specific end-use load and are applicable to other converter-interfaced large loads, including data centers

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.

This paper presents the concept, architecture, and application of a Power Plant Controller (PPC) Hardware-in-the-loop (HIL) test bench developed to support standardized control and performance testing of wind power plants in accordance with IEC 61400-21-2 and FGW Technical Guideline TR3 (Rev.26). The PPC HIL test bench, hereafter referred to as the Plant Simulator is designed as a modular, scalable, and high-fidelity test bench that emulates the electrical behavior of an entire wind power plant, including wind turbine generators (WTGs), the collector grid, additional plant components (e.g. STATCOMs, MSUs, breakers), power meters, and the external grid, while interfacing directly with the real Power Plant Controller (PPC) and SCADA system under test.

The Plant Simulator directly supports the execution of IEC 61400-21-2 functionality tests, such as active / reactive ramp rate limitation, frequency control, voltage control Q(U), power factor control and communication fallback scenarios. These tests are not site dependent, hence can be performed in a controlled and repeatable HiL environment, as specified by IEC 61400-21-2 for PPC validation. Performance tests such as active / reactive power control and controlled shutdown are site dependent (i.e., collector grid and point of connection (POC) characteristics), but still supported by the Plant Simulator under consideration of simplifications (e.g., power losses). In addition, the simulator enables FGW TR3 plant controller tests, such as determination of switchover behaviour and reconnection after grid protection events, by emulating grid disturbances, protection triggers, and recovery conditions.

Moreover, Plant Simulator facilitates the systematic comparison and validation of PPC behavior represented in OEM electrical models. HiL test results (i.e., measurements) can be compared with simulation results from offline electromagnetic transient models (e.g. PSCAD models) or real-time software in the loop solutions (e.g., RSCAD on RTDS). Importantly, these OEM reference models are derived from source code aligned with real products (PPC and WTG), enabling a consistent and traceable validation chain from component level models to plant level controller performance. The presented Plant Simulator therefore provides a robust foundation for standard compliant testing, early integration verification, and model validation of modern wind power plants.

The Brazilian Interconnected Power System (BIPS) is undergoing a structural transformation driven by the expansion of wind, solar photovoltaic, and micro- and mini-distributed generation (MMDG). This transformation is based on the superposition of a large fleet of inverter-based resources (IBRs) onto a hydro-dominated system, in which reservoir hydropower remains the main source of flexibility. This paper examines the operational challenges that follow and how they were transformed into grid code requirements. These challenges became concrete in the partial blackout of 15 August 2023, whose investigation found that wind and photovoltaic plants did not perform as their simulation models predicted. The regulatory response made model representativeness a binding requirement, and validated models are now a condition to obtain the authorization to begin commercial operation. The paper describes the resulting connection requirements, modeling obligations and compliance procedures, and the emerging grid-forming requirements for battery energy storage. These instruments are available only in Portuguese, by presenting them in a single text, the paper aims to make the Brazilian integration framework accessible to the international community of manufacturers, whose prospects in Brazil now include a record of project registrations for battery energy storage systems and more than 134 GW of offshore wind projects seeking environmental licensing

The expansion of variable renewable generation is increasing the need for operational flexibility in the Brazilian power system. This study examines the regulatory evolution of demand response (DR) in Brazil and identifies the conditions required for its integration into the National Interconnected System as a structured flexibility resource. A qualitative document-based analysis of scientific, technical, regulatory, and institutional sources is conducted. The assessment covers resource adequacy, short-term balancing, congestion management, renewable-energy absorption, curtailment mitigation, and prospective offshore wind integration. The Brazilian framework has evolved from pilot and emergency-oriented initiatives towards structural and availability-based arrangements. Further consolidation requires differentiated products defined by response time, duration, location, availability, and delivery reliability, supported by robust baseline methodologies, measurement and verification, telemetry, performance assessment, aggregation, and coordinated settlement. Demand-side flexibility can support renewable integration through load reduction, load shifting, and controlled consumption increases. Its effectiveness in mitigating curtailment, however, depends on the cause and location of the operational constraint. DR should therefore complement hydroelectric coordination, transmission expansion, storage, forecasting, and distributed energy resources within a diversified flexibility portfolio.

When analysing the integration of electrolysers with renewable energy systems, it is common to obtain hydrogen generation from mathematical models, many of which do not consider system degradation, leading to an overestimation of hydrogen generation.

This paper presents a scenario-analysis framework for evaluating the impacts of local energy communities on distribution network performance and associated economic implications. A distribution network comprising residential, commercial, and industrial prosumers, defined as per their demand profiles, is considered. Scenarios are constructed based on all possible community compositions and benchmarked against a reference case in which prosumers purchase electricity under a self-consumption strategy. Each scenario is implemented in two stages. First, operating schedules are optimized to minimize total energy procurement cost. Second, optimized schedules are evaluated using linearized distribution power flow equations to assess network performance. Each scenario is evaluated using network KPIs, including maximum feeder loading and minimum nodal voltage, and economic KPIs, including energy cost, peak cost, and overall cost. The results suggest that local energy communities primarily achieve overall cost minimization through reductions in peak-related costs. Across all local energy community configurations, 13% cases exhibit a higher maximum line loading than in the reference case, with these instances predominantly associated with homogeneous prosumer compositions. This effect arises from the mismatch between local community demand patterns and aggregate feeder demand. While batteries reduce the peak of a homogeneous community, their charging during community low-demand hours can coincide with the feeder peak, leading to higher maximum line loading at the network level.

As distributed energy resources are increasingly integrated into low voltage grids, there is growing interest in preventive control strategies to anticipate and mitigate voltage and line loading violations. Recent approaches combine probabilistic forecasts with corrective actions to trigger preventive interventions before violations occur. However, residual violations persist even in advanced simulation studies and preventive control frameworks. When planning system improvements, it is often unclear whether failures stem primarily from forecast uncertainty or from insufficient flexibility, as both factors interact and their individual contributions cannot be directly observed.

This work investigates an attention-based approach for the combination of wind power forecasts, in which soft-weights are dynamically assigned to individual power forecasts through a learned attention mechanism. In contrast to traditional methods like linear regression models, an attention mechanism computes context-sensitive weights at inference time, allowing the combination to respond dynamically to the specific characteristics of each forecast situation. Additionally, the learned weighting structure captures non-linear dependencies between base forecasters, which static combination rules cannot express. Unlike conventional combination approaches that rely on repeated retraining to keep model weights aligned with recent observations, the proposed method follows a semi-adaptive design: once trained, the attention mechanism adapts to the forecast combination implicitly through its learned weighting structure, witho

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.

Past years development is moving fast with respect to Hybrid Power Plant especially with batteries as storage units and with their rapid evolution it is becoming increasingly beneficial to incorporate large battery systems both as a stand-alone system in the power grid and inside hybrid power plants. A status is evaluated and gap analysis is investigated to design a Hybrid Power Plant with respect to dynamical performance and current operational requirements. Does every production unit or storage facility need to comply with connection requirements on its own or does it make sense to regard the facility as one whole plant? What about overplanting – where sizing of the power plant module exceeds more than 10% of the exchange capacity? New legislation regarding overplanting is submitted recently from Danish TSO Energinet in December 2025.

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 inverter-based resources into modern power systems has attracted significant interest from the industry. Extensive research has been conducted to understand the performance of these resources under various network conditions, particularly in low short-circuit level or weak grid conditions. Despite this progress, system operators still face challenges in fully understanding modern grid behavior during extreme operating events. These challenges are further amplified when offshore wind farms are considered for black start restoration, as this rare operating mode involves extremely low short-circuit levels and introduces additional technical complexities.

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.

Grid-forming control enables power converters to operate as controlled voltage sources behind an impedance. In this context, grid-forming converters can be broadly classified into two main types: those employing an inner current-control loop (CC-GFM) and those employing direct voltage control without an inner current-control loop (VC-GFM). Since voltage-source operation has recently been identified as essential for grid-connected converters in the newly published ENTSO-E and UNIFI grid codes for grid-forming generators, VC-GFM is inherently well suited to meet this requirement. In contrast, CC-GFM incorporates a current-control loop that directly enforces current limitation. Its performance strongly depends on the method used to generate current references during transients. These current references are typically generated by a current estimator. In this work, a dynamic estimation model (DEM) combined with a transient virtual resistance is proposed as an alternative to the quasi-static estimation model (QSEM) widely adopted in CC-GFM applications. The proposed approach demonstrates that the operation CC-GFM can closely emulate the small-signal behaviour of an ideal voltage source, as exhibited by VC-GFM architectures. Using both a single-unit infinite-bus (SUIB) configuration and a two-converter system connected to a weak grid, the responses of the proposed DEM-based CC-GFM, QSEM-based CC-GFM, and VC-GFM to small disturbances are compared. The electromagnetic transient simulation results demonstrate that the proposed DEM-based CC-GFM exhibits behaviour closely aligned with that of VC-GFM and outperforms the QSEM-based CC-GFM in terms of small-signal stability.

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.

The growing adoption of Electric Vehicles (EVs) introduces new uncertainty into power system operation, increasing importance of EV charging-session forecasting. This study addresses the capability of Large Language Models (LLMs) in forecasting EV charging sessions, across such variables as start time, duration, and amount of transferred energy. LLM-based prompt strategies are benchmarked against mean and median baselines, and classical machine-learning models using an 80/20 chronological split with a walk-forward protocol. The analysis is conducted on a real-world dataset from Electric Vehicle Supply Equipment (EVSE) operated in Porto, Portugal, containing 2,933 sessions from 69 users and 13 EVSEs. The results indicate that LLMs outperform the considered baselines and machine-learning models in predicting the start time of the next charging session. In contrast, transferred energy and duration predictions show no consistent improvement, with simpler models performing better in some cases. This suggests LLMs can capture useful temporal charging patterns, but hybrid approaches may be required for robust transferred energy and duration forecasting.

25th Wind Integration Workshop 2026, Porto

Grid‑Forming Control of DC‑Connected Offshore Wind Parks: Requirements, Technical Limitations and Contribution to Instantaneous Reserve

Sebastian Höhn, Georg Deiml, Konstantin Jakob, TenneT TSO GmbH, Germany

Tobias Neumann, Pascal Winter, Katharina Günther, Amprion GmbH, Germany

Since 2019 the German Grid Code includes the requirement of “dynamic voltage support without reactive current specification” and “contribution to instantaneous power reserve”. Both of them define a grid forming (GFM) control function for DC connected power park modules (PPMs) on a very high functional level, without specific details and quantification of GFM functionality.

As the extraction of kinetic energy from a wind park for the instantaneous reserve is highly restricted by aerodynamics, rotor-dynamics and the mechanical loads of the wind turbines, there was a clear need of technical in-depth investigations to consider the limitations of DC connected PPMs providing GFM service. Due to the large number of offshore wind park already in operation and those still to be built, DC connected PPMs do have a large potential to serve the system need for instantaneous reserve in the German and Continental European Synchronous Area.

Considering technical challenges on the one hand and the large potential on the other hand, TenneT TSO Germany GmbH (TTG) had invited to a project independent collaboration with wind industry at the Wind Integration Workshop 2023 in Copenhagen, with the goal of establishing GFM DC connected PPMs. General concepts and actual considerations have been presented within the Wind Integration Workshop 2024 in Helsinki.

In parallel, the technical readiness of HVDC technology to connect and integrate instantaneous reserves from the offshore wind parks has been taken forward in a separate workstream with the HVDC suppliers.

The feedback of the HVDC and wind turbine suppliers based on detailed analyses of technical solutions, system needs and internal studies have been gathered by TTG and Amprion to define a set of requirement for GFM of DC connected offshore wind turbines. The TSOs consider the requirements to be realizable in quantitative and technical terms of grid forming control, as they do consider the limitations, capabilities and characteristics of the wind turbines, being well different to other GFM technologies. Furthermore, with this first generation of GFM wind turbines the electrical and mechanical design may remain unchanged, thus GFM is a pure software solution so far. Subject to this condition, wind industry can stay with its state-of-the-art standard design of grid following wind turbine mechanical layout and primary equipment. Even with this restriction, TTG and Amprion do see a significant contribution to system stability.

These requirements form the starting point for the realization in ongoing and future offshore grid connection projects. In the final paper and at the Workshop, TenneT and Amprion will present the details of requirements for GFM, the steps and studies to be performed in the process of grid code conformity.

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.

Increasing electrification of university campuses and the growing integration of renewable energy systems have highlighted the importance of assessing the resilience of local electrical infrastructures under different operational and disturbance scenarios. In this context, university campuses can be considered representative small-scale urban environments due to their diversity of buildings, energy consumption profiles, and distributed energy resources. Consequently, they constitute suitable case studies for analysing the resilience of electrical systems based on real operational data.

• 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.

Europe’s power system and its operation is undergoing profound transformation. This is driven by multiple structural trends including decarbonization, rapid electrification, increasing cross-border power flows, and a reshaping of both generation and demand. A key feature across all such efforts is the growing converter-interfaced technologies across the system. In this evolving context, grid-forming (GFM) capabilities can play an important role in supporting voltage and frequency, improving fault behaviour, and strengthening overall system resilience. The wind sector is actively advancing GFM solutions and sees strong potential for deployment at scale. However, an effective roll-out requires careful consideration of technical, operational and economic aspects to ensure that requirements are aligned with system needs, industrial readiness, and the efficient deployment of renewable energy for Europe's energy security and decarbonisation targets.

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 ongoing energy transition presents a range of challenges,

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.

This paper gives an insight into current research activities on optimized grid operation methods, organized by voltage level, that support the integration of wind and solar and address related challenges in today’s power systems. This includes extra‑high voltage offshore systems, high‑voltage grids and medium/low‑voltage grids, with battery storage as a cross‑level element.

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

Hybrid power plants combining photovoltaic generation, wind generation and battery energy storage are increasingly expected to provide controllable power exchange, voltage support and disturbance response, rather than only renewable energy production. Most present systems use voltage source converters and static transformers. This approach is mature, but it contributes little physical inertia, and its short circuit current is limited by power electronic converter rating. These limits become more important as renewable plants are connected to weaker distribution networks and conventional synchronous generation is displaced.

This paper presents a co-simulation approach that directly connects PSCAD with an aeroelastic wind turbine tool, enabling EMT studies that combine specialised modelling capabilities from the electrical and mechanical domains. A co-simulation module, consisting of a custom dynamic link library (DLL) and a Windows Service, is developed by Fraunhofer IWES to connect both environments with minimal integration effort. To demonstrate its applicability, simulations are carried out with a representative manufacturer model of a multi-megawatt wind turbine. We replace the EMT model's simplified mechanical representation with a detailed aeroelastic model. The co-simulation is excited by mechanical and electrical step functions in the form of a sudden increase in wind speed and a voltage dip, respectively. Plausible agreement is observed when comparing the simplified and detailed model in the time and frequency domains, while the simulation speed remains constant. This study describes the technical basis for future studies of electromechanical interactions during grid-forming operation. Future work will extend the signal interface and integrate test bench models to provide a complete digital representation of grid-forming (GFM)-controlled wind turbine testing and validation campaigns.

Brazil's National Interconnected System (SIN) has become one of the world's largest wind markets, with a fleet concentrated in the Northeast and South subsystems. As penetration deepens, fast variations in aggregate wind generation—wind ramp events—are emerging as a first-order operational constraint. Yet a country-wide, plant-level characterization of ramp frequency, severity and seasonality based on official operator data has not been published for Brazil. This paper introduces the first open ramp-event catalog for the SIN, built from 30-min plant-level generation and installed-capacity records published by the Brazilian System Operator (ONS) for January 2022 to June 2026. A streaming detection pipeline scans every plant time series and registers a ramp whenever the absolute change in active power exceeds 20% of the local installed capacity within an interval of up to three hours; overlapping events are deduplicated and plant names normalized. The resulting catalog contains 2,933,162 ramp events. Three findings stand out. First, ramps are common rather than exceptional: about one quarter of all 30-min intervals initiate a ramp, reaching 45% in Bahia in the late afternoon. Second, activity is sharply concentrated—Bahia and Rio Grande do Norte alone account for 63% of events—and frequency and severity decouple: the most ramp-prone states are not the most severe, and the diurnal signal appears in frequency but not in normalized severity. Third, absolute event counts and ramp rates (MW/h) grow with the fleet, whereas per-plant frequency and capacity-normalized severity remain statistically flat (Mann–Kendall p = 0.52), indicating that the growing ramp burden is fleet-driven rather than meteorological. These results suggest that ramp-aware planning anchored to national aggregates would systematically underserve the regions where operational stress is most acute.

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.

Hydro-dominant power systems are often assumed to be inherently flexible, with their reservoirs absorbing the variability of added wind and solar. We test that assumption in the Brazilian National Interconnected System (SIN) as wind and solar capacity expand rapidly and unevenly across its four subsystems. Because flexibility in such systems is usually assessed at the national level—which hides structural heterogeneity between regions—we use eight years of hourly operational data from the system operator (ONS, 2018–2025)—energy balance, plant-level generation, interregional interchange, and reservoir energy—to resolve the flexibility constraint by subsystem, against operational adequacy criteria rather than statistical descriptors. The constraint proves to be neither system-wide nor incidental but regional and structural, concentrated in the wind-heavy Northeast. Three methodologically independent dimensions converge: (i) the Northeast is the only subsystem whose local dispatchable fleet cannot follow its own net-load ramp—ramp coverage 0.51 against the adequacy threshold of 1; (ii) it leans on interregional imports to ramp, both routinely and heavily (net-load-ramp/import correlation 0.87, and 76% of its marginal ramp met by imports, far above any other subsystem); and (iii) a simplified three-dimensional indicator ranks it lowest (p < 10^-20, Mann–Whitney), its ramp-adequacy component eroding year on year as wind and solar expand, whereas the hydro-rich subsystems' scores instead rise and fall with the hydrological cycle. Grid-driven curtailment corroborates the diagnosis: the Northeast concentrates 86.8% of the national electrically driven constrained-off energy. Flexibility planning anchored to national aggregates will therefore systematically underserve the region where the integration challenge is most acute.

Wind and solar curtailment in Brazil exceeded 10 TWh in 2024, but only cuts classified by the system operator as electric/external-unavailability reasons (REL) are reimbursable, and the regulator is currently revising the rules that define the cut categories. This paper provides the first event-level link between transmission disturbances and renewable curtailment in the Brazilian Interconnected System. We structure the complete set of 853 disturbance bulletins (BISE) issued by the ONS between 2012 and 2026 and connect each event to the official half-hourly plant-level constrained-off records under a conservative rule: a plant enters an event only if curtailed at the disturbance onset, the onset reason defines its category, and only same-reason cuts accumulate over the event window. Of the 194 disturbances in the period with public curtailment data, 41% show no curtailment response and 23% coincide with REL cuts. Around the onset, REL cuts peak exactly at t_0 and decay within hours, while reliability (CNF) and energy-surplus (ENE) cuts do not, indicating that the reason classification is empirically identifiable. Valuing attributed cuts at the hourly spot price yields 172 GWh and R$ 20.8 million of REL curtailment in the six hours following the 159 isolated events, out of 944 GWh and R$ 147.8 million across all categories. We also find that 30% of the bulletins lack a defined cause, and that the official severity index (GIE) does not register generation-side impacts.

Renewable curtailment for energetic reasons in Brazil increased from 4.4 TWh in 2024 to 20.2 TWh in 2025, while the national freight system remains dependent on diesel-fuelled road haulage. This work evaluates the contribution of mini distributed generation (mini-DG) to energetic curtailment and provides a techno-economic and geospatial assessment of a decentralized green hydrogen production and refuelling network for heavy-duty road transport in Southeast Brazil. Semi-hourly ONS curtailment data (2024–2025) were combined with the ANEEL mini-DG registry, PVGIS irradiance, EPE self-consumption factors and DNIT road and traffic data over a 1,850-hexagon grid. Curtailment was reallocated to mini-DG units according to their injected surplus and then distributed homogeneously across cells, after which PEM electrolyzers and hydrogen refuelling stations (HRS) were sized per cell under five operating strategies. Mini-DG could account for about 3% of national and up to 17% of Southeast/Midwest energetic curtailment. Curtailment-driven configurations yielded a levelized cost of hydrogen (LCOH) of 26.44–50.92 $/kg, dominated by low utilization rates (12–23%) and electrolyzer CAPEX, whereas a grid-extended full-load operation reached 10.57 $/kg at the cost of 29.7 TWh of additional demand. The resulting hydrogen could cover 39–56% of the reported internal Southeast freight distance and the full demand under extended operation, avoiding up to 6.82 MtCO2/year. Feasibility nonetheless remains conditional on complementary revenue, namely oxygen valorisation and the PHBC fiscal credit programme.

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.

Distribution grids require better visibility of emerging household flexibility, yet comprehensive device-level measurements are rarely available. This paper investigates whether a limited set of secure, minute-resolution smart-meter measurements can be transformed into grid-relevant knowledge for a residential low-voltage network. Based on 20 TAF10 measurement streams and a transformer measurement from a live German deployment, the approach first quantifies data availability, latency and electrical plausibility. It then applies an interpretable NNLS/XGBoost-assisted population-reconstruction method to estimate household and controllable-load composition from P-Q features. The reconstructed population is embedded in a minute-resolution network model comprising photovoltaic systems, electric vehicles, heat pumps, batteries and decentralised model-predictive home energy management. The study evaluates whether individually optimised flexibility reduces network stress or creates new coincidence effects. The same field-calibrated flexibility representation is subsequently used as the information layer for an Energy Sharing Community, in which alternative 15-minute allocation rules can be assessed before productive community operation. By connecting measurement validation, population reconstruction, grid-impact assessment and community coordination, the proposed workflow demonstrates how secure smart-meter infrastructure can support distribution-grid planning and local renewable-energy sharing without requiring full appliance-level observability.

In high-power charging for battery-electric heavy-duty vehicles, predictability of charging sessions at public charging stations can be valuable for both vehicles and charging infrastructure. For drivers and fleet management, predictability enables reliable route planning under constraints. For charging stations, advance knowledge of charging demands supports efficient operation under grid limitations, including control of local energy storage systems or grid services. Furthermore, coordination of charging locations and timings across vehicles may help distribute grid load, balance charging station limitations, and reduce waiting time.

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.

Germany’s uniform DE–LU bidding zone masks large internal congestion and therefore gives renewable generators no locational

Inverter-based resources (IBR) performance issues and modelling deficiencies have been documented in the NERC alerts from 2023 to 2025. NERC disturbance reports have also found that the existing models are unable to reproduce the IBR behaviours during the reported events. The authors have attempted to replicate a local voltage-reactive power oscillation event in a high IBR-penetration area by modelling the local transmission system and IBRs in electromagnetic transients (EMT) domain. The work highlights the criticality of metering delay representation and modelling the discrete nature of the power plant controllers in reproducing and predicting stability. The event replication in system simulation demonstrates that representing the metering delay as the first order lag function, which is the most common representation in standard library positive sequence models used in the western interconnection of the US, was inadequate for IBRs, especially those with large delays in feedback signals.

The transition from grid-following (GFL) to grid-forming (GFM) converter technologies is transforming the technical requirements for integrating inverter-based resources (IBRs) into modern power systems. Unlike conventional GFL converters, GFM technologies provide voltage-source behaviour, frequency support, weak-grid operation and black-start capability, making their dynamic performance a key concern for transmission system operators (TSOs). However, manufacturers implement these functions using diverse control philosophies, resulting in heterogeneous dynamic behaviours that require objective and consistent assessment. This paper reviews the principal behaviours currently evaluated during GFM verification, including voltage-source operation, current limitation during faults, temporary GFM-to-GFL transitions, weak-grid performance and black-start capability. It also analyses the evolution of operator verification frameworks towards technology-neutral, performance-based approaches that assess the observable electrical behaviour of converters under representative operating conditions. The review identifies an emerging international convergence towards technology-neutral, performance-based verification principles, with electromagnetic transient (EMT) simulation becoming increasingly important for assessing GFM behaviour. The findings highlight the need to evaluate converters based on measurable electrical performance, supported by validated EMT models and system-level test scenarios, rather than on control-implementation labels alone. These developments are expected to support the secure and reliable large-scale integration of renewable generation and battery energy storage systems (BESS) into low-inertia power systems.

The increasing penetration of inverter-based resources (IBRs), often accompanied by the displacement of synchronous generation, is changing the frequency dynamics of power systems by reducing conventional rotational inertia while increasing the potential contribution of fast active-power support. This paper investigates the combined influence of system inertia, load-frequency damping, disturbance magnitude, and IBR-based fast frequency response (FFR) using a reduced-order frequency-response model including conventional primary frequency response (PFR). A systematic sensitivity analysis is performed across different inertia, damping, and generation-loss conditions. Consistent with established frequency-response behaviour, reduced inertia results in a larger magnitude of the initial rate of change of frequency (RoCoF), deeper and earlier frequency nadirs, and a compressed corrective-action window. The effectiveness of FFR is assessed for different activation delays, showing that activation timing becomes increasingly relevant as system inertia decreases. This relationship is further investigated through a numerical FFR gain–delay capability boundary under a severe low-inertia condition. The results demonstrate that FFR effectiveness is determined not only by the magnitude of the active-power contribution but also critically by its activation timing, and that sufficiently late responses cannot necessarily be compensated by increasing the response magnitude.

The paper discusses the main challenges in the grid integration of Battery Energy Storage Systems together with renewable power plants when Hybrid Control at the plant level and the Grid Forming Control at PCS level are utilized. The combination of the BESS with existing or newly built Wind Plants shows that top challenges are related to Grid Code compliance of Hybrid plants at connection point and controllers’ interoperability. This is mainly due to split of control functionalities between Master Plant Control, Slave Control loops and Power Electronic converters with variety of control approaches. In order to control a renewable plant optimally the special approach needs to be applied allowing that Grid forming capabilities are fully present at the Point of connection, especially, in the case of the fast grid events when Frequency Converters (PCS) are acting individually without coordination form Master (hybrid) controller. Beside of the Grid Forming response, the modern Hybrid Plants are expected to be able to operate in island mode and to provide system restoration support. When performing the hybrid plant related studies, the challenge is in realistic representation of the all-hybrid plant components in order to cover a different detailed phenomenon such as latency and the control loops stability. This is typically investigated by Hardware in the Loop that is shown in the paper. The situation gets more complex, when the simulation models and control hardware are provided by several different OEMs. The paper presents an approach where the grid code compliance of the plant components are validated by real time simulation to achieve entire plant control verification. Beside of grid code evaluation, paper presents also another hybrid application where BESS provides an emergency supply to a Wind Park. That means that BESS during the loss of the network supply is providing energy from batteries to perform emergency stop by safe positioning of the wind turbines by yawing and pitching.

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

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.

Central Asia: A Living Laboratory for Future Power Systems

Supporting Caribbean Utilities: A Technical Assessment of PV Integration in Island Grids

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

Instruments for Central Asia - EU Cooperation

“How do countries deal with High PV penetration” examines the evolving challenges associated with integrating high shares of solar photovoltaic (PV) generation into modern electricity systems amid unprecedented global deployment growth.

The paper identifies key technical and market-related challenges arising from increased PV penetration in IEA countries, including network congestion, limited grid hosting capacity, declining market value of electricity during periods of high solar generation, and growing requirements for system flexibility.

To address these challenges, the paper collects successful strategies from different countries. First, smarter grid operation is promoted through dynamic export limits, flexible grid connection arrangements, advanced monitoring, and digitalized network management. Second, market-based mechanisms, including dynamic electricity pricing, flexible network tariffs, and reforms to feed-in remuneration schemes, are employed to provide economic incentives for system-responsive generation and consumption. Third, investments in storage and flexibility resources, such as battery energy storage systems, demand-response programs, electric vehicle charging management, aggregators, and energy communities, enhance the capability of power systems to balance supply and demand. Fourth, improved utilization of existing grid infrastructure is achieved through shared connections, grid-capacity transparency, and proactive congestion-management practices.

Drawing upon regulatory and operational experiences from multiple countries, including Australia, Austria, Germany, Italy, Spain, the Netherlands, and the United Kingdom, the paper demonstrates that successful large-scale PV integration increasingly depends on flexible, digitally enabled, and market-oriented electricity systems to sustaining PV expansion while ensuring secure, reliable, and efficient grid operation in future renewable-dominated energy systems.

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-wear costs, and operational costs to estimate annual savings, payback period, and return on investment (ROI). 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. The peak reductions achieved by both investigated AC configurations remain below the discounted annualized-cost break-even requirement, although the higher-power configuration achieves a simple payback within the assumed project lifetime and a positive undiscounted ROI. The economic conclusion therefore depends on the financial metric applied.

The deployment of heavy-duty electric vehicles and high-power charging infrastructure introduces new operational requirements for managing their integration into the power grid. This presentation introduces the PowerUp project, which is developing a modular and scalable smart-charging solution for heavy-duty electric vehicles. The system combines interoperable 1.5 MW Megawatt Charging System technology with intelligent energy management, renewable generation and battery storage. Its integration with the power grid enables coordinated control of charging demand, local frequency response, remote dispatch, demand response and participation in system services, while respecting vehicle priorities and site constraints. Real-time monitoring, AI-enabled predictive maintenance and augmented-reality support aim to increase infrastructure availability and reduce downtime. By coordinating charging, photovoltaic production, storage and grid requirements, the solution seeks to reduce operating costs, emissions, demand peaks and pressure on the power network. The project ultimately aims to validate the integrated architecture in a real operating environment, achieve TRL 9.

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).

The Central Asian Interconnected Power System is undergoing a significant transformation driven by rapid growth in electricity demand, increasing cross-border power exchanges, and large-scale deployment of variable renewable energy (vRE), particularly solar photovoltaic (PV) and wind generation. While the region possesses abundant renewable energy resources and strong potential for regional electricity market development, the increasing penetration of inverter-based renewable generation introduces new technical challenges that affect secure and reliable operation of the interconnected synchronous power system.

Definition of an Energy Storage Strategy for Portugal up to 2040

Energy storage is becoming a strategic asset for the decarbonisation, flexibility and security of the Portuguese electricity system. The National Energy Storage Strategy aims to accelerate its integration through a technologically neutral regulatory framework, simplified licensing and grid connection procedures, appropriate economic signals, and effective participation in electricity and system service markets, with a planning horizon extending to 2030–2040.

The presentation discusses the methodology adopted to support this strategy for future reinforcement of battery storage energy systems and reversible hydro plants, combining scenario analysis based on Portuguese NECP and Security of Supply Monitoring projections, assessing impacts on security of supply, energy and secondary reserve markets, and analysis of technological, regulatory and financial barriers. Particular attention is given to the role of storage in electricity market prices, where it can reduce renewable curtailment, displace thermal generation and exploit price arbitrage, while also affecting the operational revenues of renewable generation and storage technologies themselves.

Storage is also shown to be critical for security of supply, although its contribution must be complemented by demand flexibility, adequate thermal backup and, in the longer term, seasonal storage solutions. The proposed action plan defines storage deployment targets with capacity mechanisms, full participation in new ancillary services such as Fast Frequency Response, inertia and voltage/reactive power support, and requirements enabling Grid Forming operation. Overall, the strategy positions storage as a central enabler of a more renewable, resilient and economically efficient Portuguese power system.

The Iberian Blackout 28/04/2025 – What lessons for the future

The blackout that affected the Iberian Peninsula on 28 April 2025 was one of the most severe disturbances experienced by the European power system in more than two decades. This keynote analyses the sequence of events that led to the system collapse.

Prior to the blackout, the Spanish transmission system experienced significant voltage fluctuations and poorly frequency damped intra-area and inter-area oscillations. At the same time, conventional synchronous generation was relatively limited and geographically concentrated, while large volumes of renewable generation, especially solar PV, were connected mainly in the South of Spain under operational requirements that restricted their active participation in voltage regulation. The analysis to the available data indicated, that low system inertia was not the primary cause of the blackout, with the estimated Iberian system inertia remaining above 2.5 s. Instead, increasing overvoltage’s triggered successive losses of renewable and conventional generation, transforming a voltage stability problem into a severe frequency disturbance with loss of synchronism with the Central European system.

Using frequency and voltage measurements from the event together with physics-based dynamic modelling, it was possible to understand how the disturbance developed and identify lessons for operating future power systems dominated by converter-interfaced renewable generation. Attention is given to exploiting the voltage and frequency control capabilities of renewable power converters, strengthening and rigorously verifying grid-code requirements, and improving system-wide observability and coordinated voltage control.

The presentation concludes that the energy transition requires not only additional renewable capacity, but also a fundamental evolution of operational practices and dynamic security management solutions to be adopted by system operators. Wide-area monitoring and control, advanced operational decision-support tools, enhanced reactive-power capabilities and strategically deployed grid-forming converters will be essential to ensure that highly renewable power systems remain secure, resilient and capable of recovering from major disturbances.

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.

Australia has just installed 13,000MWh of home batteries in 12 months, versus 20,000MWh in utility-scale BESS across 8 years. Combined with increasing penetrations of rooftop PV, these government subsidised arrangements are changing the nature and dynamics of the electricity markets. This analysis discusses the full impacts.

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

Power System Stability Needs Assessment Framework

Portugal’s E-Mobility Transition: Infrastructure, Intelligence and Grid Integration

Keynote Presentation: From Renewable Integration to System Integration: A Portuguese TSO Perspective

Optimal Electrification Dynamics for Public Fleet: Balancing TCO, Infrastructure Sizing, and Battery Waste Management Processes In Aruba

From Charging to Flexibility: Lessons learned from real world V2X pilots