The energy transition toward a carbon-neutral energy system presents complex challenges that require reliable system-level insights to guide investment and policy. Energy system models are essential tools in this context. They support planning by simulating interactions between technologies, markets, and policies under various future scenarios. Their strength lies in their ability to highlight structural system relationships and test the feasibility of different energy strategies.

At the foundation of these models lie assumptions and simplifications that define the internal logic of an energy system model. Importantly, a distinction must be made between assumptions (e.g., cost or efficiency parameters) and simplifications (e.g., ignoring demand fluctuations or omitting battery interaction). While simplifications make models tractable and transparent, they also risk overlooking key real-world constraints. This is why testing the impact of these assumptions and simplifications is critical: doing so ensures that model outcomes are robust and that their conclusions remain meaningful in practical applications.

Energy modelling simulates the operation and evolution of energy systems to support decision-making and policy planning. It helps simplify complex systems, forecast scenarios, and evaluate the effects of different strategies. While models are never perfectly accurate, their usefulness depends on data quality, transparent assumptions, and iterative refinement. These assumptions directly shape model credibility and must be rigorously tested to avoid the risk of unvalidated assumptions becoming accepted truths that undermine decision-making.

One such model is the Kramer and Koning Model (KKM), a stylised energy model developed to analyse the relationship between renewable electricity generation and hydrogen capacity. The KKM is appreciated for its simplicity and its capacity to clarify the fundamental relationship between renewable energy generation and electrolyser capacity - the r : e relationship. However, this simplicity raises the question of how sensitive its results are to added real-world complexities and how valid its outcomes remain. This study addresses that knowledge gap by investigating: "How Do Key Model Assumptions in the KKM Influence the Relationship Between Renewable Energy and Electrolysis Deployment?".

To evaluate the validity of KKM outcomes, this study introduces the Electrolyser Battery Balancing Model (EBBM) - a more detailed cost optimisation model operating under the same logic as the KKM, but with extensive additional parameters. The EBBM simulates hourly interactions between renewable supply, demand, electrolysers, and batteries. Developed in collaboration with Gasunie, a key player in the Dutch gas infrastructure and hydrogen transition, the EBBM is specifically designed to test real-world factors and find the cost-optimum interplay between renewable, electrolysis, and battery capacity. It is well-suited to validate the simplified relationships modelled by the KKM.





Firstly, a systematic identification of assumptions in the KKM was made. These were categorised as either explicit or implicit. Implicit assumptions were further divided into (1) real-world system simplifications (e.g., omitting compressors, conversion losses), and (2) wider context simplifications (e.g., sector coupling, market conditions). Based on their role in the model and feasibility for testing in the EBBM, a focused selection of assumptions was made, grouped into four categories: renewable energy, hydrogen, cost, and system simplifications. The eventual selection consisted of:

• Generation Mix;
• Electrolyser Efficiency;
• Electrolyser Limitations;
• Hydrogen Storage Cost;
• Cost Ratio between Renewables and Electrolysers;
• Neglect of Demand Fluctuations;
• Battery Interaction Exclusion;
• Demand Flexibility.

Moving on with the selected set of assumptions and simplifications, a sensitivity analysis was first conducted by incrementally reintroducing high-certainty system simplifications to the KKM base case. This included adding demand fluctuations, battery interaction, electrolyser efficiency curves, hydrogen storage cost and electrolyser limitations to create a new, more realistic base case. This updated case was then used to test the impact of four key parameters: electrolyser efficiency, demand flexibility, solar share, and the cost ratio between renewables an electrolysers. In each case, a high and low value was tested. These variations were used to assess how much each assumption shifts the r : e relationship, battery sizing (r : b), and total system cost (c).

Firstly, the incremental addition of complexities resulted in a flatter slope and lower overall system cost compared to the original KKM. Further results showed that parameters like solar share and cost ratio significantly affect infrastructure allocation between batteries and electrolysers, while demand flexibility and efficiency assumptions moderately shift total system cost and capacity sizing. The r : e relationship remained structurally linear in all cases but varied in slope and magnitude. Notably, the combination of battery interaction and electrolyser efficiency assumptions produced the largest cost savings, lowering total decarbonisation cost by several hundred euros per kW relative to the KKM.

A robustness analysis followed, designed to assess whether model outcomes remain valid under extreme input conditions (edge cases). These edge cases were selected for the same assumptions as for the sensitivity analysis. The aim was to evaluate whether the KKM’s simplified relations hold up under stress. The results indicated that while the relationship itself remains observable, its quantitative implications (e.g., cost and deployment levels) vary substantially, suggesting that the relation needs to be interpreted as directional rather than predictive.

To further contextualise the findings, a comparative model analysis was conducted. This compared the r : e relationship in the KKM against other existing energy system models. A longlist was developed and refined to three studies: CE Delft, E-Bridge, and a NSWPH study. Extracted data confirmed that while each model uses different frameworks, a consistent structural trend in the r : e relation is present, supporting the underlying logic of the KKM, albeit under different boundary conditions.
Despite differences in geography, modelling scope, and sectoral integration, all three studies showed a similar acceleration in electrolyser deployment relative to renewable generation, particularly beyond 2040. This convergence across models suggests that the r : e relationship is a robust feature of future energy system dynamics, rather than an artefact of a specific model setup. It reinforces the validity of the KKM’s structural assumptions, even if absolute outcomes vary. As such, the r : e relation emerges as a valuable comparative indicator for system modellers and energy planners aiming to align infrastructure scaling with decarbonisation timelines.

In the discussion, the findings reveal that while the KKM offers a robust conceptual tool, its practical outputs are assumption-sensitive.. Key limitations include the use of a single weather year to simulate renewable variability, a strictly unidimensional approach to parameter varying, and the degree of certainty with which a particular impact can be attributed to an assumption in another model. These issues are particularly important for policymakers or investors relying on model outputs for long-term infrastructure decisions.

The conclusion confirms that the KKM captures a fundamental structural relationship between renewables and hydrogen capacity, which reappears when evaluating other models. However, the outputs of the KKM are highly dependent on assumption quality and scope, especially regarding solar share and the cost ratio between renewables and electrolysis. The research shows that integrating high-certainty simplifications and testing uncertain variables adds valuable depth. Therefore, the KKM proves useful for identifying strategic trends in the r : e relation. Future research should extend this work by incorporating power-to-heat, more detailed battery interaction, and policy scenarios to increase applicability in real-world system design.
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Green hydrogen is seen as the future for decarbonizing industrial sectors in the Netherlands. A key strategy for its adoption is the development of on-site storage facilities, enabling industrial companies to balance variable supply with high energy demand. However, the absence of a clear and supportive institutional framework hampers large-scale adoption. Existing research focuses heavily on technological solutions, overlooking the interplay between regulations and stakeholder behavior. This study addresses that gap by using an agent-based model (ABM) to simulate stakeholder interactions under different storage ownership scenarios. The results inform actionable policy recommendations for regulatory frameworks that promote safety, scalability, and collaboration—paving the way toward a sustainable hydrogen system. ... Read more

The Netherlands has set ambitious climate targets, aiming to become climate neutral by 2050, which implies a 100% reduction of greenhouse gas emissions compared to 1990 levels. Solar and wind power are key to replacing fossil fuels in electricity generation, but their intermittent output creates a need for both short-term and seasonal energy storage. At the same time, sectors such as heavy industry, aviation and shipping remain challenging to electrify directly. Renewable hydrogen, also referred to as RFNBO-compliant hydrogen, is emerging as a clean and flexible energy carrier that helps fill the gaps where green electricity alone is not enough. It can be stored, transported, and used in applications where direct electrification is not feasible. Unlike grey hydrogen produced from fossil fuels, renewable hydrogen is made by using electricity from solar or wind to split water into hydrogen and oxygen, significantly reducing carbon emissions.
Producing renewable hydrogen remains expensive due to the high capital costs of electrolysers and the limited availability of cheap renewable electricity. Producing renewable hydrogen in a way that is both economically sustainable and scalable is important to decarbonize global industries and provide renewable seasonal storage. To evaluate and compare the economic performance of hydrogen production methods, the Levelised Cost of Hydrogen (LCOH) is used. LCOH represents the average cost of producing hydrogen over the lifetime of a facility, accounting for capital, operational, and energy costs. As the renewable hydrogen market is not yet completely developed, metrics such as Net Present Value (NPV) are less suitable for determining the competitiveness of the technologies. Therefore, it is important for renewable energy companies, like Eneco, to create renewable hydrogen with the lowest LCOH to be competitive in the hydrogen market.
One approach to lowering costs is to pair electrolysers with batteries, where revenues from storing electricity and selling it to the grid, known as arbitrage revenue, can help offset operational expenses. This can be achieved through two types of systems: the Battolyser, an innovative technology that combines battery storage and hydrogen production in a single device, and a system where a battery and electrolyser are co-located but operate as separate units. These systems have distinct advantages and disadvantages, which have not yet been evaluated and compared. Therefore, the main research question is: How does the Battolyser compare to a system with a separate battery and electrolyser in achieving the lowest levelised cost of hydrogen (LCOH) compliant to RFNBO (EU) standards?

To answer this question, this research analyses four different co-located system configurations. Each configuration combines either an alkaline or PEM electrolyser with an LFP lithium-ion battery or a vanadium redox flow battery, selected for their technological maturity and future potential. Together with the Battolyser, the five systems considered are:
• Battolyser
• Alkaline electrolyser + Lithium-ion battery
• PEM electrolyser + Lithium-ion battery
• Alkaline electrolyser + Redox flow battery
• PEM electrolyser + Redox flow battery

Financial and technological characteristics of the systems have been identified, taking the Dutch market into account. The five systems are simulated by using a novel techno-economic simulation model that has been created for this research. The model simulates the systems in a framework based on Dutch hourly electricity prices between 2030 and 2050.
The simulation model focuses on three main operational strategies: battery charging, battery discharging, and hydrogen production. The systems are simulated on an hourly basis for the period 2030–2050, using a combination of mixed onshore wind and solar power profiles contracted through a Power Purchase Agreement (PPA), together with grid electricity as power input in the base case simulations. The model uses a controller with a three-hour receding horizon to anticipate electricity price fluctuations. The simulation framework ensures an objective comparison by keeping operational strategies and regulatory compliance consistent while varying system-dependent parameters such as electrolyser efficiency, minimum stable load, and system costs.

The base case simulations showed that the Battolyser performs best with an LCOH of 9.96 €/kgH2. Among the four battery-electrolyser combinations, the system with a lithium-ion battery and a PEM electrolyser came closest to matching the performance of the Battolyser, followed by the alkaline and Li-ion system. Although redox flow battery systems have longer lifespans and flexible sizing, their higher costs result in poor LCOH performance, because the technical benefits do not compensate for this. The LCOH values lie close to each other, with a spread of 1.40 €/kgH2 when including redox flow systems, and just 0.40 €/kgH2 when excluding them.
Several analyses, including sensitivity and scenario analyses, were performed to understand the robustness of these findings. A local sensitivity analysis was performed by varying electricity prices by plus and minus 20% compared to the base case, to examine how changes in electricity costs impact LCOH performance. This analysis showed that the PEM + Li-ion system, followed by the ALK + Li-ion system, both perform better than the Battolyser when the electricity prices increase, as the systems can take full advantage of the flexibility by dynamically shifting operation. They can produce hydrogen at nominal capacity during one hour, switch to battery charging the next hour when electricity prices are low, and then sell electricity back to the grid during high-price periods. In contrast, the Battolyser performed significantly worse under these increased conditions, as it cannot separate battery operation from hydrogen production, which limits the system’s ability to fully exploit price fluctuation.
In the global sensitivity analysis, five key parameters (CAPEX, OPEX, electrolyser efficiency, battery capacity, minimum stable load) were varied to investigate the absolute effect on the LCOH, as well as their interaction with other parameters. This analysis shows that varying the electrolyser efficiency has the highest absolute effect on the LCOH. In addition, electrolyser efficiency is present in every statistically relevant interaction term. This shows that electrolyser efficiency is not only a significant factor on its own but also influences the impact of other parameters, making it the most important determinant of LCOH.
This is confirmed in the scenario analysis, where the systems are simulated with a more steady offshore wind power profile, in contrast to the mixed wind on land and solar power profile in the base case. The Battolyser and alkaline systems, both of which have better electrolyser efficiencies than the PEM system, perform better under these steady conditions. In contrast, the PEM-based systems show a decline in performance, requiring significantly lower offshore wind PPA prices to achieve LCOH levels similar to those in the base case. This indicates that under stable power conditions, electrolyser efficiency becomes a more dominant factor in contrast to operational flexibility.
Finally, the Battolyser and co-located systems were compared to standalone alkaline and PEM electrolysers. The standalone systems outperformed the hybrid configurations due to their lower cost structure and ability to channel all available power directly into hydrogen production. The alkaline electrolyser achieved a lower LCOH than the PEM system in the base case, the reduced electricity price scenario, and under an offshore wind profile. This advantage can be attributed to its higher electrolyser efficiency. These findings indicate that adding a battery to an electrolyser does not necessarily lead to lower LCOH. However, the standalone systems lacked operational flexibility, making them perform worse under scenarios with higher and more volatile electricity prices, where the PEM + Li-ion system performed better.

In conclusion, this research explored whether combining battery storage with electrolysis could lower production costs through electricity market arbitrage. The Battolyser was compared with four battery-electrolyser systems for renewable hydrogen production. The results show a small spread in LCOH and that there is no single system that performs best across all situations. Among the hybrid systems, the Battolyser achieves the lowest LCOH in the base case, the reduced electricity price scenario, and under an offshore wind profile. Its strong performance can be attributed to its high electrolyser efficiency, which proves to be a significant factor in determining the LCOH. Nonetheless, standalone electrolysers outperform the Battolyser in these scenarios due to their lower cost structures and direct power use. However, when electricity prices rise and become more volatile, systems with separate batteries and electrolysers perform better, with the PEM + Li-ion configuration achieving the lowest LCOH.
It is recommended that Eneco prioritizes hydrogen production systems with high electrolyser efficiency as a strong option for RFNBO-compliant hydrogen. Standalone electrolysers should be considered when electricity prices are expected to follow patterns similar to the base case. However, Eneco should remain open to using separate battery and electrolyser setups in case when electricity prices are expected to rise. Since the LCOH differences between systems are relatively small, it is further recommended that the system selection should be guided by additional factors such as environmental impact and the availability of technologies within the European market.

While the system choice is important to provide a competitive edge in the hydrogen market, the results also highlight a broader challenge for renewable hydrogen. Eneco expects that the willingness-to-pay for renewable hydrogen will be approximately €9/kgH2. No system is able to produce renewable hydrogen below this threshold and thus a cost gap remains. Therefore, future research should investigate the renewable hydrogen market in the Netherlands and potential subsidy schemes. Moreover, it is recommended to expand the simulation model to allow a more detailed comparison between the systems as this simulation model has some limitations. Possible additions include incorporating optimization horizons that reflect the day-ahead electricity market, enabling dynamic power allocation, exploring participation in additional energy markets, and performing environmental life cycle assessments. ... Read more

The Green Village (TGV), located at TU Delft, is a regulatory-free field lab where innovative projects relevant to the energy transition are tested in a built environment. In this context, seasonal storage is considered a promising research pathway for TGV, as increasing renewable energy penetration and resulting grid congestion are expected to make seasonal storage a key factor in the energy transition. The objective of this thesis is to assess whether liquid organic hydrogen carriers can provide a feasible seasonal storage solution for the TGV community and to compare it to a compressed hydrogen storage pathway.
A literature review was conducted to shape the research angle of this thesis by gaining insights from relevant studies, identifying the principles and components necessary for the LOHC process, and examining existing safety regulations and measures applicable to this storage pathway. The review identified that economic viability was hindered by the heat supply, carrier selection, and system integration. At the same time, an evident gap was found for community-scaled systems and for studies that model the entire energy system under varying loads. Currently, there is no clear regulatory framework for hydrogen storage, as it is still in development. However, several studies focused on the safety of hydrogen-related components suggest using PGS 35 as a technical guideline. This document outlines the necessary permits, safety measures, and distance requirements for such installations. For the LOHC, there is currently no specific regulatory framework; however, some studies suggest that PGS 29 may be applicable to certain aspects of the process. The system of focus for this study is a community-scale hybrid energy system connected to the grid for TGV. This system comprises a PV system, a LiFePO4 battery for short-term storage, an electrolyser for hydrogen production, seasonal hydrogen storage, and a PEM fuel cell for electricity generation during periods of low PV output. For this system, two separate hydrogen storage pathways were developed. The primary scenario involves an LOHC-based hydrogen storage system (a quick overview of this scenario can be found in Figure 1.2). In this scenario, hydrogen is bonded to the LOHC through hydrogenation during summer for seasonal storage. Then, during winter, when PV availability is scarce, it is converted back through dehydrogenation. In the second scenario, hydrogen is stored in compressed gas cylinders (an overview of this system can be found in 3.4). Both pathways’ operation was modelled to follow the energy management system currently applied in TGV Energy Hub 24/7. This prioritises direct PV use, daily battery cycling, and extended operation of the electrolyser during the summer (with one start per day) to produce the seasonally stored hydrogen, as well as dispatch of the Fuel Cell during winter utilising the stored hydrogen. This way, grid exchanges are minimised as they occur only after all internal energy sources have been fully utilised. To assess the feasibility of these scenarios, a techno-economic model was developed in MATLAB. The model employs a modular approach, creating a module for each component of the system. The overall sizing and cost estimation are conducted by a main script that simulates the entire calendar year 2023 at an hourly resolution. The model preprocesses load and PV inputs, applies three hard constraints that limit annual PV export to 10%, annual grid import to 5% of load, and annual LOHC mass balance deviation to 0.5%, and then runs the EMS, battery, electrolyser, hydrogenation, dehydrogenation, and fuel-cell modules. Peak duties and temperatures are extracted for ASPEN EDR heat-exchanger sizing and costing. Economic results are reported as CAPEX, OPEX, LCOE, NPV, and IRR. The validation of the model is conducted through internal checks of the EMS logic, evaluation of pitch diagrams to ensure thermodynamic consistency, and comparison of results with established manufacturer and literature values. For the LOHC scenario, the optimal configuration is found for 552 PV modules with a total capacity of 165.6 kWp, a 261 kWh battery, a 116 kW electrolyser, and a 34 kW PEM fuel cell. Annual grid import is 0.88 % of load, and annual PV export is 8.79 %. Summer electrolysis produces about 1,813 kg of hydrogen that is stored in the NEC. Annual hydrogenation produces 30,986 kg of hydrogenated carrier. Dehydrogenation releases 1,610 kg of hydrogen, of which 898 kg is used by the PEM fuel cell and 710 kg is combusted for process heat. The annual requirement of hydrogenated NEC is 30,591 kg, which results in a mass-balance deviation of 0.41 %. Waste-heat recovery covers 88 % of hydrogenation preheat duty and 11.4 % of dehydrogenation duty. An overall system efficiency of 41.4 % is found, with 49.5 % for the LOHC chain and an electrical round-trip efficiency of 23.4 %. The capital expenditure is €2.36 million, of which €1.64 million is attributed to the LOHC process and about €1.16 million to the initial NEC fill. The operational expenditure is €12,901 per year. The levelised cost of electricity is €1.695 per kWh with an NPV of −€2.67 million and an IRR of −29.5 %. The total footprint of the LOHC system was found at 1,020 m2 while the space required for the process tanks and reactors is estimated at 66 m3 when two tanks are used and 36 when a single tank is used. For the alternate scenario with compressed hydrogen, the same EMS and component models are used, except for hydrogenation and dehydrogenation. This scenario resulted in a PV system consisting of 379 PV modules and totalling 113.70 kWp, the same battery and PEM fuel-cell sizes, and an 80 kW electrolyser. Annual PV export is 10.38 % and annual import is 1 % of load, with an annual hydrogen balance error of 2.09 %. The capital expenditure is €565,306, and the operational expenditure is €6,004 per year. The levelised cost of electricity is €0.79 per kWh with an NPV of −€0.732 million and an IRR of −18.21 %. The total area required for the system is approximately 699 m2 while the space used for the 1,039 50L tanks required a total of 52 m3.
Sensitivity analysis indicates that the discount rate is the principal driver of LCOE variation within a range of about −9.8 to +10.3 %. Project lifetime produces a range of about −5.8 to +9.5 %. LOHC process costs, in particular the carrier, produce changes of about ±8 % in LCOE and have notable effects on NPV.
Concluding, the case study shows that a PV–battery–electrolyser–fuel-cell system using LOHCs can deliver near year-round autonomy at The Green Village, but its energy efficiency is constrained by dehydrogenation heat demand (only 12% high-grade heat recovered with PEMFC) and consequent hydrogen combustion, which limits the electrical round-trip efficiency to 24% despite strong waste-heat integration on the hydrogenation side. Economically, LOHCs remain impractical at current prices as CAPEX is dominated by the LOHC chain (including the NEC inventory) and yields an LCOE around €1.70/kWh with strongly negative NPV/IRR, whereas a compressed-hydrogen baseline achieves similar operational adequacy at far lower cost but still fails to reach profitability under base assumptions. The feasibility is primarily influenced by financing conditions and the lifespan of components, with LOHC specific costs (particularly the price of the carrier) being the next most significant factors. In contrast, the costs associated with PV/batteries are less critical. This suggests that improvement efforts should focus on enhancing high-grade heat integration (such as SOFC fuel cells), reducing capital and operational expenses in the LOHC chain, and implementing financing or policy strategies to lower capital costs. Finally, safety and siting considerations favour LOHC’s ambient-condition liquid storage for built environment applications, while the compressed-gas alternative required as high amount of pressure vessels and safety setbacks; taken together, these results suggest LOHCs are technically feasible with a favourable safety profile, but deployment hinges on cost and heat-management breakthroughs or supportive market frameworks before community-scale adoption becomes realistic
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Electric vehicle (EV) adoption in the Netherlands has been increasing, as a response to climate change and urban pollution. A scale up of the public charging infrastructure is required to satisfy the future charging demand. This is a challenge for the policy makers and stakeholders involved, as there are still many uncertainties in EV adoption and mobility. The goal of this research is to identify pathways to scale-up the public EV charging infrastructure in residential areas. The research takes into account various perspectives and challenges related to the EV transition, such as mobility policy, charging behavior, energy infrastructure, and accessibility of the charging infrastructure. The main research question is:

”How can public EV charging infrastructure in residential areas be scaled-up?”

The study contains five chapters to answer this question. Four of these chapters include studies that were published in journals and conference proceedings. The research approach consists of literature studies, data analysis, policy analysis,multiple criteria analysis, and agent-based modeling. The individual studies all contribute to understanding different parts of the charging system. The following paragraphs summarize each of the five studies. ... Read more

Green hydrogen is emerging as a critical component in the global fight against climate change, offering a viable pathway to reduce greenhouse gas (GHG) emissions and facilitate the transition to a low carbon economy. As renewable energy sources (RES) like wind and solar become more prevalent, the challenge of their variable supply and the resulting green hydrogen production, demands robust energy storage solutions to ensure stability and flexibility in the energy supply. Underground hydrogen storage (UHS) in salt caverns has been technically proven as an efficient and effective method to address these challenges. However, despite the growing need for UHS, the development of such projects is lagging behind.
The study applied and extended the Institutional Network Analysis (INA) method to the case study of UHS in salt caverns in the Netherlands. The INA method is designed to identify institutional relations and analyse how formal and informal institutions interact within an institutional environment. In this research, the method was modified to focus exclusively on formal institutions, excluding informal institutions. Two extensions were made to deepen the analysis. First, a rule typology analysis was added to analyse the key characteristics of the formal rules within the institutional environment. Second, the approach was further refined by categorizing drivers behind institutional connections.
The application of the extended INA methodology uncovered several critical insights into the institutional environment governing UHS in salt caverns. First, the study identified a misalignment between the Dutch government’s policy intentions, as outlined in the Subsurface Spatial Planning Vision, and the actual practices dictated by the Environment and Planning Act. While the Act emphasizes participation and the opportunity for third parties to propose solutions, the Vision often rules out these possibilities by pre-determining the most fitting solution for a specific problem. Second, the analysis revealed an institutional void, particularly in the area of participatory governance. Although many formal institutions advocate for a participatory approach, the policy documents lack clear guidelines on how third parties should be included in decision-making processes and how the effectiveness of participation strategies should be assessed. Next, the study highlighted the central role of specific actors, such as the competent authority and project developers, who hold significant influence within the institutional network. Additionally, several objects related to permit applications and operational procedures were identified as potential bottlenecks due to their high embeddedness scores. Lastly, the analysis of the rule typology revealed that boundary, information, and position rules are the most prevalent within the institutional context. This suggests that the institutional environment is heavily focused on regulating access and exit within the context and ensuring the dissemination of information to relevant stakeholders. ... Read more

Hydrogen is becoming increasingly integral to global energy transition strategies, especially in sectors difficult to electrify. In the Netherlands, industrial clusters are expected to be key centers for sustainable hydrogen supply and demand. However, smaller industries outside the main clusters (Cluster 6) face significant challenges due to their distance from major demand points and the complexities of integrating hydrogen into their operations. They struggle with the high initial investment costs for on-site hydrogen generation, limited access to decarbonization subsidies, and the technical challenges posed by a congested electricity grid. The lower priority given to these regions in the hydrogen roll-out plan exacerbates the uncertainty and hesitancy among Cluster 6 industries, threatening the efficient development of regional hydrogen infrastructure and creating a risk of underutilization. The research employs a modeling approach and agent-based simulation to analyze the potential for collective action to overcome technical, economic, and institutional limitations, facilitating hydrogen production and consumption among smaller, dispersed industries. This approach allows for comparative analysis of emergent system behavior under different organizing principles, agent interactions, and government policy interventions. The simulation results highlight that collective investment is key to successful hydrogen transitions, with unified strategies leading to quicker and more effective outcomes. When driven by individual efforts instead of collective action, transitions tend to face delays and result with less sector inclusion. In regions with more hydrogen-dependent companies, contribution of collective action grows exponentially, with primary off-takers initiating the shift. However, relaxing subsidy criteria in such regional settings can weaken regional cooperation and slow progress. Therefore, designing region-specific policies that promote collaboration and encouraging communication and inclusiveness among companies can help achieve a smoother and more unified regional shift to hydrogen. Future research should address the limitations of the current study by incorporating more detailed cost-benefit analyses, exploring alternative hydrogen supply and transportation methods, and considering a broader range of factors influencing industrial decisions on hydrogen adoption. ... Read more

Hydrogen is a crucial element in the transition to a sustainable energy system, with the Netherlands poised to use it in transportation, heating, and energy-intensive processes. Due to its existing gas infrastructure and strategic location, the Netherlands has the potential to become a leader in hydrogen technology, distribution, and trade. Despite numerous announcements and plans, the development of hydrogen distribution networks has yet to fully take off. European initiatives such as the European Hydrogen Backbone promote cross-border cooperation and hydrogen market formation. In the Netherlands, HyNetwork Services (HNS) is tasked with developing a national hydrogen network connecting major industrial hubs. However, at the regional level, no responsible parties have been appointed, and regulations are lacking. To develop efficient and effective regional hydrogen distribution networks, a clear regulatory framework is needed to provide stakeholders with security, clarity, and direction.

This research aimed to analyze the current and upcoming regulations influencing hydrogen distribution networks and to formulate possible reforms to accelerate their development. The main research question was: “How can regulatory frameworks influence the development of Dutch regional hydrogen distribution networks?” The research methodology involved a comprehensive literature review, stakeholder identification, and institutional analysis. The Institutional Analysis and Development (IAD) framework was employed to examine the regulatory context, while Institutional Grammar (IG) was used to simplify regulatory documents into institutional statements. Institutional Network Analysis (INA) provided a detailed map of these statements and their interactions. Data collection included document analysis and semi-structured interviews with key stakeholders from regulatory bodies, industry, and overarching organizations. These interviews offered crucial insights into the perspectives of actors in the Dutch hydrogen sector regarding current regulations, perceived barriers and drivers, and preferred changes or additions.

Key findings revealed that the primary regulatory documents governing hydrogen projects—the Environment and Planning Act, the Gas Act, and the Electricity Act—lack the specificity needed to support hydrogen network development. Upcoming regulations, such as the Energy Act and the EU Decarbonisation Package, emphasize integrating renewable energy sources, specifying roles in the future system, and laying the foundation for a hydrogen market. Stakeholders perceive the current regulatory environment as fragmented and insufficient, necessitating clearer guidelines and more supportive policies to reduce uncertainties and foster investment.

Identified barriers include the complexity of the permitting process, grid congestion, insufficient subsidy schemes, and the lack of norms and standards tailored to hydrogen. Conversely, drivers include the strategic importance of hydrogen in the energy transition, national and EU-level incentives, and hydrogen's potential to alleviate grid congestion and enhance energy security.

Based on document analysis and stakeholder interviews, several recommendations were made. These include simplifying the permitting process through increased flexibility in provincial ordinances, establishing a clear and robust subsidy scheme, implementing specific guidelines for hydrogen, and enhancing stakeholder collaboration. For regulatory bodies, it is advised to establish a dedicated national entity with Distribution System Operators (DSOs) to oversee hydrogen projects and streamline regulatory processes. DSOs should develop convincing development and investment plans, actively engage in the planning and development of hydrogen networks, and ensure regulatory alignment with energy transition goals.

The study also explored potential future strategies for regional hydrogen networks. These include the formation of independent hydrogen networks, expansion and integration of these networks into larger systems, and direct connections of regional clusters to the hydrogen backbone by DSOs. Addressing regulatory barriers and enhancing support mechanisms is essential for the Netherlands to lead in hydrogen technology and infrastructure development, contributing to national and global sustainability goals. ... Read more

The electrification of housing and industry increases electricity demand. Furthermore, integrating Distributed Energy Resources (DER) leads to more electricity being fed back into the low-voltage (LV) grid. Both developments increase the needed capacity for electricity distribution over the LV grid. However, since the current LV grid system was not initially designed for such high demand and bidirectional electricity flow, the existing LV grid infrastructure can no longer cope with the needed electricity capacity, causing LV grid congestion. Grid congestion on the low-voltage (LV) grid can lead to stagnation in new housing construction and hinder the development of businesses and industries, thereby impacting economic development.
To manage grid congestion, DSOs must monitor the LV grid state to perform appropriate interventions. However, due to electrification and the integration of DERs, monitoring and predicting the LV grid state using the established methods are no longer sufficient to manage grid congestion properly. To perform more effective congestion management, DSOs’ capabilities for monitoring and predicting the LV grid’s state must be enhanced first. Therefore, DSOs need more observability on the LV grid. Observability is defined as measurement data measured by measuring equipment or smart meters providing feedback on the LV grid state.
Smart meters installed in homes and commercial buildings can provide the measurement data needed to increase the observability that DSOs require to improve their monitoring capabilities. Although DSOs in the Netherlands own the smart meter infrastructure, established institutions, like AVG, make it difficult for DSOs to access smart meter data since it is perceived as personal data. Efforts have been made to reduce this complexity by introducing a code of conduct, the Gedragscode Slim Netbeheer (GSN), to enable DSOs to use smart meter data. However, the need for increased observability remains. This means that the GSN does not facilitate the required observability on the LV grid, and therefore, it does not meet the values and interests of the DSOs... ... Read more

Currently, hydrogen consumption is heavily concentrated within larger inflexible industrial applications, where it is produced onsite for further downstream processing. Considering traditional production pathways have a high emission intensity, electrolytic hydrogen production could prove an essential decarbonization pathway for existing, unabated consumers and additional hard-to-abate industrial applications. While legislative frameworks limiting unwanted effects of the electrolytic hydrogen transition are being drafted, it is important to provide policymakers with quantitative data on the effects of this legislature. Other than emissions intensity standards, additionality principles are being considered in a number of these frameworks to further minimize unwanted effects. One of the central principles of additionality is a temporal-correlation requirement, which synchronizes renewable electricity generation with electrolyzer consumption over a predetermined period. The length of this period could significantly affect the intermittency of electrolyzer operations. Although this has been subject to debate, it has seen little attention in literature within the context of industrial applications, which bring substantial additional downstream constraints. It is imperative to understand the effects of these additionality principles quantitatively within the context of their dominant application, heavy industry. This could aid policymakers to arrive at a framework that minimizes the adverse effects of electrolytic hydrogen production while preventing cost increases that hinder widespread adoption.

A mixed-integer linear-programming problem is formulated to model an onsite electrolytic hydrogen production facility for a larger industrial downstream process. The downstream flexibility and temporal correlation constraints in this model are generalized to study their potential antagonistic effects abstractly. The downstream flexibility constraints considered are the minimum partial-load and the period over which production has to match the desired output, mimicking further downstream supply chain constraints. The model employs integrated design and operations optimization, considering the cost-optimal production facility will vary depending on the legislature and downstream process.

The results indicate that temporal correlation requirements affect the production costs of hydrogen as a consequence of limiting the operational flexibility. Additionally, strict temporal correlation requirements exacerbate the escalation of these costs. The availability of a geological storage site reduces the effects of temporal correlation requirements and DSP inflexibility on production costs. Regarding emissions, at current allowance prices, the ETS is not sufficient for emissions abatement of onsite electrolytic hydrogen production. On the other hand, temporal correlation requirements are an effective tool for reducing the attributable emissions intensity. However, a focus on emissions abatement for onsite electrolytic hydrogen production, without adjustments to the ETS, risks cost inefficient sectoral emissions reduction without reducing system emissions, due to leakage to other sectors. ... Read more

Sustainable energy transition is the need of the hour, more so, because of the accelerated effects of climate change. This necessitates rapid, continuous, and persuasive political and technological approaches to enable an ecosystem of green alternatives for countries to support their net-zero ambitions. One such emerging technology approach is green hydrogen, which is hydrogen produced from renewable sources. Green hydrogen is considered as a versatile energy carrier to support transitioning of industries, energy systems and transport, towards sustainability. As such, globally, many countries have increasingly considered green hydrogen as a part of their decarbonisation plans. Today, at least 26 countries have adopted hydrogen policy strategies and supporting policy instruments. However, mere adoption is not enough – a test of policy effectiveness is required to evaluate whether policies will be executed in keeping with their stated objectives, whether the various policy instruments/tools introduced to support overall strategies will be collaborative or may conflict with one another, and whether the policies will address issues systematically or ad hoc. It becomes important to understand whether policy strategies and instruments, the underlying processes, and their characteristics - collectively called a policy mix- could actually support policy goals, objectives, and ambitions of various countries. ... Read more

To combat the effects of climate change, there is a worldwide shift to reduced emissions and increased use of renewable energy sources. Solar energy is a vital part of this transition and necessary to be able to achieve the targets. The rapid pace of adaptation raises questions about the negative equity and justice associated with this development. Along with the rapid growth, regional differences in solar panel adoption have been found across the world. Besides, government incentives and policies have played an important role in both adoption growth and justice implications.

This study explores the pace and equitability of the solar energy transition in Amsterdam, the Netherlands. The study evaluates the potential for solar energy, the disparity of adoption, what socio-economic factors are correlated to adoption patterns, and how adoption might evolve in the future and under different policy measures. To do so, a structured, integrated and data-driven approach is designed to meet the research objectives, and possibly serve as a policy tool for future studies.

The study shows that there is an "adoption gap" in Amsterdam, meaning that solar panels and the benefits of incentives end up with a specific group of citizens. Therefore, targeted policy measures are necessary to ensure an equitable transition. ... Read more

Improving sustainability in industrial processes is a key topic for the welfare of the environment. One of the major environmental problems caused by industrial processes is industrial waste production. In the automotive industry, the use of polymers such as PA12 for prototyping produces tons of waste per year which are generally destined to incineration. Recycling could help reduce waste, but recycling procedures can be resource-consuming, therefore it might not always be efficient or more sustainable than traditional practices. In most cases, recycling involves extra steps in the process value chain, including finances, transportation, workforce, as well as machinery. To make sure recycling has positive effects in terms of sustainability on industrial processes, a framework to assess the sustainability of recycling procedures is needed.

In this study, it is proposed an assessment framework which considers four pillars of sustainability: (1) technical, (2) environmental, (3) economic, and (4) social. While the environmental, economic, and social pillars are usually considered in sustainability assessments, the technical pillar has been neglected and should be considered in understanding the sustainability of recycling procedures. This framework can be applied to gain insights into recycling procedures’ sustainability and help as a tool to decide which procedure to adopt. Likewise, it considers the company’s needs and objectives, as fundamental factor for the evaluation. In recycling procedures, the technical pillar should include indicators related to resource efficiency but also recycled material quality, an essential factor when evaluating their effectiveness. Such a framework, consisting of a ten steps approach, aims to facilitate the adoption of recycling procedures, through qualitative and quantitative assessments, on the basis of a set of indicators, selected within the four pillars of sustainability.
From the analysis of the current system, to the definition of objectives, design of the pathways, and the evaluation of sustainability indicators, the framework aims to allow companies to systematically assess and select a sustainable pathway in terms of defined objectives and environmental regulations.

The framework was applied to the case study of mechanical recycling of PA12 waste from automotive prototyping. The aim is to reduce plastic parts waste, to be turned into filament for Additive Manufacturing technologies for use as jigs and fixtures. Following systematically the assessment framework, ten potential recycling pathways were identified and compared. Major differences among them include the ratio of waste parts to virgin material, and filament extrusion location. The sustainable recycling pathway that resulted from the evaluation features the shortest transportation distances (connected to lower carbon footprint and energy consumption, and higher flexibility). The application of the framework provided a trade-off analysis, where not only the interests on the environment are considered, but particular attention is given to companies’ needs and opportunities.
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The European Union has set out to become carbon neutral by 2050. To reach this goal, the fossil-fuel-dominated energy system must be transformed into a low-carbon renewable-based energy system. One method proposed to reduce fossil-fuel dependence is to establish a renewable hydrogen supply chain between Africa and the European Union. This work provides a model framework that enables an economic analysis of a renewable hydrogen supply chain between northern Africa and the EU. The aim of this work is to gain a better understanding of large-scale intercontinental renewable hydrogen production by investigating the factors that impact the economic performance of this system.
A mixed-integer linear programming model that describes the supply chain is built, and modeled in Python and a case study defining the overall energy system under consideration and applied to this model. The system must provide 780 TWh of hydrogen demand for the EU in 2050. Hydrogen is produced by water electrolysis, using renewable electricity from solar photovoltaics. The water required for electrolysis is supplied through reverse osmosis of seawater. Seasonal storage of hydrogen is enabled through the inclusion of hydrogen storage in salt caverns.

The resulting annual costs of operating the supply chain are 36.55 B$, corresponding to a levelized cost of hydrogen of 1.56 $kg^-1. The main contributors to the cost of the supply chain are solar photovoltaics (50\%), alkaline electrolysis (22%), and transportation (26%). Through a sensitivity analysis on price uncertainty, it is found that the system is most sensitive to photovoltaics prices (59%), electrolysis prices (21%), and hydrogen pipeline prices (18%). A sensitivity analysis of the interest rate on capital investment points towards a significant impact of the interest rate on the total annual cost.

The findings of the model and applied case study in this work are then compared to projected costs in other works. From this analysis, it is found that hydrogen production using electrolysis will be cheaper than fossil-based low-carbon hydrogen production alternatives in the form of steam methane reforming or coal gasification with carbon capture technology. Predictions of the selected works regarding electrolysis-based hydrogen production using renewable electricity show an expected LCOH of between 1.66 - 2.39 $kg^-1.

This work indicates that a renewable hydrogen supply chain between Morocco and the EU in 2050 is both technically and economically feasible, able to compete with alternative hydrogen production methods, and able to supply 35% of the projected hydrogen demand. Moreover, this work developed a general hydrogen supply-chain model that allows for the implementation of additional features as well as the analysis of different case studies through the adjustment of case-specific parameters. ... Read more

As part of the Dutch government’s ambitions to realise significant offshore wind energy capacity (70 gigawatts (GW) by 2050), the Port of Rotterdam is to become a hydrogen hub for North-Western Europe. To achieve this, it is expected that around 20 megatonnes (Mt) of hydrogen could be throughput in the Port of Rotterdam, out of which 2 Mt will be produced locally from offshore wind farms. Current offshore wind farms use high voltage electricity cables to transport energy to shore, but could, in the future, also transport energy in the form of hydrogen to shore via a transport infrastructure.
The objective of this thesis is to investigate the techno-economical feasibility of an offshore hydrogen production value chain connected to the Port of Rotterdam. The technical analysis gives insights into the possible technologies that can be used for the offshore value chain. It will also look at the technical feasibility of system integration in the Noth Sea's energy system. The economic analysis gives insights into the economic feasibility of the offshore hydrogen production value chain. The total costs are of importance, as well as the levelised cost of hydrogen.
In this thesis, a qualitative literature study maps the different possibilities per component of the value chain. A decision framework is then used to discuss the best possibility per component and to build three promising designs. These designs are then modelled in MATLAB to size their components. With the model’s output, a cost analysis can be done to determine whether such a value chain would be feasible compared to other ongoing projects. A special focus will be put on the Port of Rotterdam, to which the value chain will be connected.
The offshore decentral configuration is found to be the best-performing design based on assessments through a multi-criteria decision analysis, a technical model and a financial model. It is, therefore, the most promising design.
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This thesis explores the transformation of the global transportation and energy sectors through the adoption of electric vehicles (EVs). EVs have emerged as a crucial solution to reduce greenhouse gas emissions and promote sustainable energy sources. The associated charging infrastructure poses challenges and opportunities for Charge Point Operators (CPOs).

Among the various charging solutions, Vehicle-to-Grid (V2G) technology offers significant potential for CPOs. However, prior research has not comprehensively addressed the financial implications, operational costs, and revenue streams specific to CPOs, particularly within the energy market.

The primary objective is to investigate public charging network business models through V2G integration in the Netherlands from a CPO perspective. The central research question is whether CPOs in the Netherlands can enhance their business model through V2G in the EPEX DAM market. The primary focus is on assessing the financial impact of V2G on CPO operations, considering factors such as electricity procurement costs, user behavior, and location-specific dynamics.

The methodology combines empirical analysis, simulation modeling, and data-driven insights. It commences with a literature review on EV charging, V2G technology, and CPO business models. Stakeholder consultations provide real-world insights into business dynamics and cost structures.

An Excel-based simulation model replicates various V2G charging scenarios using data from the European Power Exchange (EPEX) Spot Day-Ahead Market (DAM). A base case charging scenario, involving both V2G and regular charging, is developed, and the results are used to assess CPO profitability in the Public Charging Network business case.

An extended Cost-Benefit Excel model evaluates the profitability of the CPO's business model after integrating the reduced variable cost of procured electricity through V2G within the evolving EPEX DAM landscape. It considers factors such as battery degradation, customer compensation, charging behavior, and market dynamics.

The simulation models reveal pivotal findings. V2G integration strategically implemented has the potential to boost CPO profitability by significantly reducing electricity procurement costs. User compensation schemes, charging patterns, usage rates, and location-specific demand dynamics significantly influence earnings. Sensitivity analysis underscores the importance of usage rates, cost reduction for procured electricity, and network expansion in driving profitability.

In conclusion, this thesis uncovers the potential of V2G technology to enhance EV charging infrastructure while contributing to grid stability and renewable energy integration. The findings provide strategic guidance for CPOs to focus on densely populated cities to maximize revenue and profits. The insights extend beyond CPOs and are relevant to stakeholders within the EV charging ecosystem. ... Read more

We aim to make solar power forecasts using regression for grid optimization. We forecast from 1 to 6 hours ahead. The forecasts prove to be accurate with a skill score of 20% compared to persistence for a lead time of one hour. ... Read more

This study researched the optimal network of hydrogen refueling stations. The network is designed on a European scale and with a focus on heavy duty trucks. The design is created by means of a two-step optimization. The first step clusters truck representing datapoints into a predetermined number of stations by means of k-means clustering. The second step optimally connects these to a source of supply, which is assumed to be a European hydrogen backbone. Cost values of supply and demand are finally optimized by balancing a cost function.

Research was performed by order of Shell. ... Read more