Electrolytic hydrogen is expected to play a key role in decarbonizing energy systems in Europe. However, such projects face uncertain grid access due to congestion and struggle with financial viability. To address growing grid congestion in the Netherlands, different types of non-firm connection and transport agreements (CTAs) and capacity restriction contracts (CRCs) were introduced, enabling client curtailment in exchange for tariff discounts or per-MW compensation. This paper investigates investment and contracting decisions for electrolyzer projects under these novel contracts using a two-stage risk-aware stochastic optimization model that captures uncertainty in electricity prices and grid access. Results show that risk-averse clients prefer non-firm CTA-85 contracts, which balance tariff discounts with curtailment compensation, while risk-neutral clients favor standard non-firm CTAs. The new contract types can lower the break-even hydrogen price by approximately €0.50/kg compared to firm contracts outside congested areas, and thus improve the business case for electrolytic hydrogen in the Netherlands.

In response to increasing grid congestion in the Netherlands, non-firm connection and transport agreements (CTAs) and capacity restriction contracts (CRCs) have been introduced, allowing consumer curtailment in exchange for grid tariff discounts or per-MW compensations. This study examines the interaction between an electrolyzer project, facing sizing and contracting decisions, and a network operator, responsible for contract activations and determining grid connection capacity, under the new Dutch regulations. The interaction is modeled using two bilevel optimization problems with alternating leader-follower roles. Results highlight a trade-off between CRC income and non-firm CTA tariff discounts, showing that voluntary congestion management by the network operator increases electrolyzer profitability at CRC prices below €10/MW but reduces it at higher prices. Furthermore, the network operator benefits more from reacting to the electrolyzer owner's CTA decisions than from leading the interaction at CRC prices above €10/MW. Ignoring the other party's optimization problem overestimates profits for both the network operator and the electrolyzer owner, emphasizing the importance of coordinated decision-making.

The inclusion of PV and heat pumps in residential low-voltage distribution systems is a fundamental component of the energy transition. Nevertheless, adoptions below 40% can already cause voltage conditions incompliant with the standard EN50160 during winter. Aggregated storage systems have been proposed as a solution; however, the literature generally assumes full observability and controllability of the assets, which is unrealistic in many cases. This paper evaluates the potential of aggregated single- and multi-carrier storage systems to maintain voltage stability in low voltage networks, considering separated controllers for the prosumer and the aggregator. We used a real 301-node residential distribution network in the Netherlands as case study. Our results demonstrate that aggregated multi-carrier energy storage can ensure the voltage conditions established in the standard EN50160 for energy transition adoptions up to 80%, while aggregated single-carrier storage can reach 60% and centralized storage only 40%. We concluded that aggregation of storage assets increases the utilization of the existing grid infrastructure, reducing reinforcement costs for the DSOs. However, the energy storage assets’ high investment costs lead to unattractive conditions for single- and multi-carrier storage, compared to a case with only PV and heat pumps. Considering the current market conditions, using storage for voltage support would require economic compensations. These findings provide DSOs valuable insight on alternative solutions to grid reinforcement and centralized storage to address the challenges of the energy transition.

As a part of energy transition, the shift from internal combustion engines (ICEs) to electric vehicles (EVs) has accelerated the development of the EV charging infrastructure (EVCI). EVCI rely heavily on information and communication technologies (ICTs) and the Internet of Things (IoT). As a result, the susceptibility to cyber attacks increases. However, although EVCI are strongly intertwined with cyber-physical power systems (CPPSs), the consequences of such a cyber attack on the power grid are not widely researched. In this paper, we present a comprehensive cyber-physical system architecture of the EV charging infrastructure based on the industry practice in The Netherlands, which is applicable to European distribution systems. We present a survey of work on EVCI cyber security and CPPS resilience. We combine unique industrial insights with the academic state-of-the-art. We show that although cyber security of EVCI is researched, the state-of-the-art inadequately covers the consequences for CPPSs, especially distribution networks. We survey the current work on CPPS resilience and conclude that while cyber attacks are often recognized as high impact low probability (HILP) disturbances of CPPSs, the resilience-related research on cyber attacks on EVCI is lacking. Therefore, we present a novel method to model the stochastic EV charging behaviour based on probability density functions (PDFs). We validate the method using PowerFactory models of distribution networks supplied by a Dutch distribution system operator (DSO). We demonstrate the effects of cyber attacks on EVCI on distribution networks voltages. Under the investigated operational scenario, the impact is not significant. However the results do underline the importance of researching cyber attacks on EVCI from a CPPS resilience perspective. Research into future scenarios of energy transition is essential for future resilient operation of power grids.