Urged by international accords such as the Paris Agreement and the IPCC’s global warming report, the Dutch government is in the process of developing the national industrial hydrogen market across five main industry clusters. In addition, regional hydrogen demand is being explored to complement the national hydrogen backbone by connecting decentralized industrial customers outside the five clusters through regional hydrogen distribution networks. This emerging regional industrial hydrogen market is collectively referred to as Cluster 6.

Hydrogen distribution network operators (HDNOs) are expected to play a key role in this transition as neutral market facilitators at the regional level. However, as heavily regulated entities, HDNOs are dependent on appropriate regulatory frameworks. The EU’s Hydrogen and Gas Decarbonisation Package introduces a legal framework for third-party access (TPA), allowing Member States to adopt regulated (rTPA), negotiated (nTPA), or hybrid (hnTPA) regimes. In the Dutch context, regional TPA regulation remains under development. The implications of these regimes for HDNOs and regional market development are currently unclear.

This research addresses the knowledge gap surrounding the influence of TPA regimes on stakeholder behaviour and hydrogen deployment in Cluster 6. Using a case study approach, the study combines literature review, expert interviews, and agent-based modelling (ABM) to analyse how TPA regimes affect stakeholder decision-making and infrastructure rollout. Interviews were held with system operators, a Cluster 6 representative, local industries, and the municipality. Interviewees highlighted challenges due to unclear stakeholder roles and financial responsibilities. While some industries expressed interest in hydrogen, driven by visionary entrepreneurs, most remained hesitant and dependent on broader commitment. High costs and uncertainty around hydrogen pricing were key concerns. Network operators indicated that key negotiation terms under nTPA could include prioritization based on project characteristics and investment cost division.

These insights informed the agent-based model. Industrial agents in the model decide to transition to hydrogen based on a motivation score derived from peer pressure, cost-benefit analysis (CBA), and waiting list incentives. Scenarios reflect different TPA regimes and associated rules: rTPA with first-come-first-served prioritization, and nTPA and hnTPA with negotiable prioritization and cost division.

The results show that TPA regimes significantly affect the pace and scale of hydrogen deployment. nTPA yields the most favourable outcomes for hydrogen off-take and CO₂ reduction, due to prioritization mechanisms that reward large, efficient projects. However, prioritization alone does not accelerate the timing of transition unless economic conditions are also supportive.

The investment cost division plays a stronger role in influencing the pace of transition. When industries are partially relieved of investment costs (under nTPA and hnTPA), the model shows shorter average waiting times and an earlier final transition year. Even when hnTPA switches to rTPA, results remain favourable due to early negotiation-phase decisions. Together, the negotiation terms support more ambitious transitions and earlier uptake.

Based on these findings, the study recommends clarifying stakeholder roles and financial responsibilities, assigning an HDNO, and considering scenario-based price guarantees. HDNOs could use negotiation terms to incentivize cost-efficient projects and introduce cost-sharing mechanisms to reduce risk. Both actors should promote visibility and flexibility in early-phase TPA design to increase motivation for hydrogen adoption.

In conclusion, third-party access regimes play a crucial role in shaping the regional hydrogen transition. While regulated TPA delays progress, negotiated TPA supports more ambitious and timely outcomes. Hybrid regimes offer a partial solution but depend on economic conditions and timing.

The energy transition in the Netherlands, characterised by the increase of renewable energy sources (RES) and the electrification of key sectors, has placed strain on the existing electricity grid. Challenges such as volatile electricity prices, curtailment of excess renewable energy, and grid congestion highlight the limitations of the current infrastructure, particularly in urban low-voltage (LV) networks. Here, transformers get congested due to limited capacity during peak hours. Expanding the grid is often infeasible due to high costs, long timelines, and spatial constraints. However, Renewable Energy Communities (RECs) have emerged as a promising solution to these challenges by optimising the use of the existing infrastructure within local contexts.

The challenge in improving affordability, sustainability and security is that the goals are contradicting, also referred to as the Energy Trilemma. Therefore, this thesis addresses the research question: “How can Dutch urban Renewable Energy Communities be designed and operated to enhance energy affordability, sustainability, and security?”. To answer this, a multi-objective linear programming (MO LP) model was developed using the Calliope software framework in Python. The model optimizes the design and operation of RECs across three energy trilemma dimensions: affordability, sustainability, and grid security. It incorporates solar photovoltaic (PV), battery energy storage systems (BESS), and grid interactions.

The research underscores the inherent trade-offs in balancing the energy trilemma. Affordability-driven scenarios minimize costs through extensive grid reliance, increasing emissions and transformer congestion, while sustainability- and grid-security-focused scenarios emphasize self-consumption, reducing both but incurring higher costs and curtailment. Maximizing solar PV capacity cuts CO₂ emissions but leads to substantial curtailment without sufficient storage or trading. BESS mitigate imbalances by shifting energy flows in time, yet grid dependence remains unavoidable, especially in winter when PV output is low.

There is thus no universally optimal REC design, effectiveness depends on stakeholder priorities. However, key insights hold across all scenarios: Dutch urban RECs can enhance affordability, sustainability, and security with approximately 750 kW of solar PV per 200 prosumers and 200 kW MV and LV batteries for hourly balancing. Designing RECs this way, could offer a more efficient solution for mitigating urban grid congestion than defaulting to grid expansion.

Despite its contributions, the study has limitations. The model simplifies grid interactions by focusing solely on the LV grid and transformer congestion, excluding medium-voltage (MV) and high-voltage (HV) dynamics. Behavioural feedback on market dynamics, such as the impact of widespread REC adoption on electricity prices, or the diminishing business case of batteries, is also not captured. These limitations underscore the need for future research to expand the model’s scope, address emerging technologies, and integrate multi-layered grid interactions that include feedback systems.

All findings of this thesis are open source. The model that was developed to answer the research questions can be accessed at:

https://github.com/Tomdebruin/MO-LP-Energy-Community-optimisation

Green hydrogen production through electrolysis is increasingly recognized as a critical pathway for decarbonizing the energy sector. However, the integration of electrolyzers with renewable energy systems presents several technical and economic challenges. Renewable energy sources such as wind and solar are inherently variable, leading to fluctuating power inputs that impose dynamic operating conditions on electrolyzers. These fluctuations result in degradation mechanisms, such as start-stop cycles, partial load operation, and power ramping, which reduce efficiency and impact long-term performance and economic viability. While technical challenges related to degradation have been investigated in prior research, the role of hydrogen support mechanisms, such as price premiums, in addressing these challenges remains underexplored.

This thesis extends an existing optimization framework to incorporate degradation effects into the modeling of electrolyzer performance. Degradation is represented asdynamicreductions in efficiency that evolve based on operational conditions, including cycling and variable load profiles. A rolling horizon approach is employed to simulate the cumulative impact of degradation over time, enabling the study of electrolyzer operations under realistic renewable energy inputs. The model evaluates two distinct scenarios: one in which electrolyzers operate without external policy intervention, and another where hydrogen support mechanisms are integrated into the framework. This separation allows for an examination of how these factors independently influence electrolyzer scheduling, efficiency, and the economic viability of green hydrogen production.

The findings indicate that degradation significantly influences electrolyzer performance under variable renewable energy conditions, with dynamic operating profiles leading to efficiency losses over time. The inclusion of hydrogen support mechanisms in the analysis highlights their potential to improve economic feasibility by partially mitigating the financial challenges posed by variability. However, the results are contingent on model assumptions and emphasize the importance of considering operational and market-specific factors when assessing the impact of such mechanisms.

By addressing both technical and economic aspects, this thesis contributes to the understanding of howelectrolyzers performunder variable power inputs and howpolicy mechanisms might influence their operation. The results provide a foundation for further research into optimizing electrolyzer performance and integrating green hydrogen into renewable energy systems.

The global wicked problem of environmental sustainability issues forces us to work on understanding the collective and complex nature of our current systems. Large businesses and organizations are known to play a crucial role in influencing environmental sustainability, with their impact on the environment being significant and multifaceted. The ever-increasing environmental concerns have put large companies under scrutiny from different stakeholder groups like regulators, consumers, employees, investors, activists and non-governmental organizations (NGOs). Consequently, corporate environmental sustainability and performance have become a strategic priority. However, the corporate environmental landscape has evolved into a complex system of interdependencies due to dynamically changing regulations and stakeholder expectations. Furthermore, corporate environmental performance (CEP) is a multidimensional construct influenced by a complex interplay of internal organizational factors as well as external business environment factors. As a result, companies often struggle to make effective decisions to enhance CEP, leading to a gap between ambition and effective action toward corporate environmental sustainability.

The existing literature presented a critical gap in understanding the interactive and holistic effects of the most critical factors influencing CEP. Building on the knowledge gap and the identified problems, the primary objective of this study was to support large companies in the Netherlands in improving their CEP by analyzing and identifying the interplay of the most critical factors within technological factors, organizational culture, corporate governance, and external stakeholder pressures that significantly impact CEP. Hence, the following central research question was formulated: How can large companies utilize the interplay of technological factors, organizational culture, corporate governance, and external stakeholder pressures to enhance corporate environmental performance?

The study adopted an inductive, semi-quantitative research design, utilizing the fuzzy cognitive mapping (FCM) approach. Initially, a literature review was conducted to conceptualize CEP and identify factors associated with it. Then, data was collected through 10 semi-structured interviews with experts from various stakeholder groups, including large companies, consultants, academia, and research organizations. Furthermore, qualitative content analysis of the interview transcripts was performed to identify the factors influencing CEP and the relationships among them, leading to the development of individual FCMs. These individual FCMs were subsequently combined into an aggregated FCM. Then, a structural analysis of the aggregated FCM was conducted to determine the nature and importance of the factors identified. The aggregated FCM was further condensed (simplified) to facilitate more in-depth analysis. Finally, to formulate strategies that might enable large companies to improve their CEP, the findings from the structural analysis were integrated with an analysis of the pathways through which different factors influence CEP. This resulted in three sets of strategies: the first based on high centrality factors, the second on high direct impact factors, and the third on low centrality transmitter concepts.

The results identified 26 critical factors influencing CEP within the broad categories of technological factors, organizational culture, corporate governance and external stakeholder pressures. Furthermore, the developed aggregated FCM demonstrated how these factors interact to influence CEP by highlighting the complex causal interrelationships between the identified factors. Moreover, the study formulated 14 strategies that might enable large companies in the Netherlands to enhance their CEP. The first two sets of strategies defined 12 priority strategies. Furthermore, the third set of strategies provided two guiding strategies to enhance the effect of the variables involved in the priority strategies.

Furthermore, the study establishes that interactions among various factors significantly influence CEP. Hence, it emphasizes that future research should take an integrated and holistic approach when investigating the impact of factors influencing CEP. Moreover, the study encourages companies to formulate strategies that include the interactive effects of different factors to create a more holistic approach to enhancing CEP. By considering the interplay between the identified factors, companies can develop more nuanced and effective strategies that do not merely target individual factors in isolation but rather address the broader system of influences. In addition, the study provides an FCM template that companies can use as a decision-support tool, enabling them to understand the potential outcomes of different strategic choices and allowing them to simulate how changes in one area might affect others. By using the FCM, companies can devise specific strategies by taking into account their unique circumstances, industry, and external environment.

In conclusion, the study highlights the importance of an integrated and holistic approach to improving CEP, considering the complex interplay between internal and external factors. The study contributes to the academic field of corporate sustainability and management by filling a significant knowledge gap concerning the interplay of critical factors influencing CEP. The findings provide insights for companies to enhance corporate environmental sustainability, ultimately contributing to broader global sustainability goals.

The study recommends future research to focus on validating the developed FCM and the strategies to improve CEP. The findings can be validated by integrating quantitative methods such as regression models, organizing workshops with focus groups, and conducting scenario and sensitivity analyses.

Hydrogen is emerging as plausible energy carrier to decrease the global dependency on fossil fuels. Hydrogen production based on renewable energy and electrolysis is a technically mature and well-researched production process. Production processes based on large electrolyzers result in varying and relatively high (between €4/kg and up to ± €14/kg) levelized costs of hydrogen - attributable to high electrolyzer and electricity costs. This research evaluates the potential of an off-energy-grid PV and small- capacity electrolyzer based hydrogen production process. The assessed smaller-capacity electrolyzers result in less than a quarter of most electrolyzer costs (€/kW). The cost reduction combined with the avoided electricity costs due to grid connection, allow for market competitive LCOHs within the range of ± €2,15-5/kg hydrogen depending on the hydrogen outflow system chosen for the farm. This research shows that the low electrolyzer and electricity costs of an off-energy-grid PV and small-capacity electrolyzer based hydrogen farm - with running hours limited to the average sun equivalent hours while including a water supply system (source, treatment, distribution across farms, etc.) and a hydrogen outflow system (collection across farm, possible compression) - has technical feasibility and market potential.

Global warming has increased societal awareness and the use of renewable energy, leading to the gradual replacement of fossil fuel vehicles with electric vehicles (EVs). To earn revenue, reduce electricity outages, increase grid stability, and incentivize the switch to EVs, parked EVs can discharge electricity into the grid through Vehicle-to-Grid (V2G) technology.

Transport hubs like airports are ideal for V2G projects due to their many parking spots and long parking durations. To determine financial feasibility, Cost-Benefit Analysis is a commonly used tool to compare two situations or cases. However, there are no CBA studies done on V2G in transport hubs like airports, presenting a significant literature gap.

This study hence analyzes the financial feasibility of a V2G project at Schiphol Airport using Financial Cost Benefit Analysis (FCBA) and risk analysis. The study aims to determine the conditions under which the project is commercially feasible by looking at the Benefit-to-Cost ratio, and at associated risks that might impact the success of such a project.

The analysis covers a seven-year period from January 2024 to December 2030 and is based on profit maximization theory. Key costs include V2G chargers and fees paid to EV owners, while benefits include revenue from electricity sales and carbon credits. The study compares a Base Case of expanding unidirectional EV charging with a Project Case of implementing bidirectional V2G charging. Results indicate that frequency regulation provides a Benefit-to-Cost ratio greater than one, making it the most viable method for generating revenue. Falling charger costs and a minimum V2G utilization rate are found to be crucial for the project’s financial feasibility.

The conducted risk analysis identifies potential challenges and propose mitigation strategies. The main risks include the potential unwillingness of grid operators to pay for FFR services and low adoption rates of V2G among EV users at Schiphol Airport. To mitigate these risks, the study suggests collaborative efforts with grid operators, awareness campaigns to educate EV users, and government support to incentivize V2G adoption. Given that the project's financial outlay is less than 1% of Schiphol Airport's annual infrastructure budget, the study concludes that the project is financially viable despite the identified risks.

Future research areas include using proprietary data from Schiphol Airport to enhance the accuracy of the study, particularly regarding parking and charging patterns of EVs. This research provides valuable insights into the V2G ecosystem as it is the first time a cost-benefit analysis is being conducted for a V2G project at a transport hub. It supports V2G’s application at transport hubs and paves the way for future real-life projects.

The transport sector in the Netherlands is under pressure to reduce emissions, constituting about 12% of the country's total emissions, to align with the goals of the Paris Agreements. One promising solution is the adoption of hydrogen fuel cell heavy-duty trucks, particularly for long-haul transport, providing emission-free operation when sourced from renewable energy. While existing literature covers the financial and technological aspects of adopting hydrogen trucks, there is a noticeable gap concerning the social effects of this transition, which are crucial for a comprehensive evaluation of a subsidy program.
This thesis conducts a Social Cost-Benefit Analysis to assess the viability of subsidizing hydrogen fuel cell heavy-duty trucks in the Netherlands. By examining both costs and benefits, it aims to offer insights into the societal implications of transitioning from diesel to hydrogen trucks. Using a mixed-methods approach including stakeholder interviews and data analysis, the study evaluates emission reductions and social gains associated with this subsidy program.
The analysis considers two scenarios based on the future market share of hydrogen trucks and three subsidy program initiation dates (2024, 2030, and 2040), extending the assessment until 2050. Results indicate that initiating the subsidy program in 2024 yields the most favourable outcomes, yielding positive Net Present Values of 1.8 billion euros and 2.4 billion euros for the respective scenarios. Nevertheless, substantial subsidy costs are anticipated, with estimated expenses of 4 billion euros and 12 billion euros for each of the two 2024 scenarios, surpassing the government's proposed budget.
The study highlights uncertainties related to infrastructure costs and assumptions regarding economies of scale, underscoring the need for further investigation before implementing the subsidy program. Addressing these uncertainties is crucial for achieving a more precise understanding and ensuring the social viability of transitioning to hydrogen fuel cell heavy-duty trucks in the Netherlands.

The automotive industry is transitioning to electric vehicles (EVs), creating a higher electricity demand. Concurrently, the utility sector is shifting to a renewable energy system. Vehicle-to-grid (V2G) technology allows EVs to both consume and deliver electricity to the grid, introducing a dynamic interaction. However, integrating EVs into the grid raises challenges related to grid safety, such as the risk of overloading. To address this, additional technical specifications are needed. The EV charging industry relies greatly on international standards. Therefore, market players seek clear guidelines for products enabling bidirectional power flows. However, technical requirements specific to V2G systems remain unspecified or divergent, creating obstacles for technology development and implementation by the industry. Harmonisation and standardisation of technical specifications are considered effective means for overcoming these challenges. However, existing literature lacks insights into the necessity and realisation of harmonisation. This study fills this gap by exploring the extent, reasons, and coordination efforts required for harmonisation of technical requirements specific to V2G. Particularly, this study investigates barriers stemming from the technical implementation of V2G and their impact on the adoption by key stakeholders.

An open-minded approach following the grounded theory principles identified primary obstacles in the technical implementation of V2G. The grounded theory approach included conducting semi-structured interviews with ten participants, which helped explore perspectives and needs of five key stakeholder groups. In addition, a comprehensive framework is consulted to provide a theoretical lens assisting the interpretation and analysis of the empirical results. Integrating the widely adopted Institutional Analysis & Development (IAD) framework and Multi-Level Perspective (MLP) aided in identifying and understanding the interplay between institutional arrangements, such as technical requirements and standards, and technology adoption. This novel approach has proven to be valuable in analysing the relationships between micro-level interactions (IAD) and macro-level influences (MLP).

This study has shown it is unclear to niche actors how to become "V2G-ready" due to a lack of clear guidelines, especially related to the charging standard (AC or DC), the communication standard between system operators (DSOs) and charge point operators (CPOs), grid connection codes, and who should be in control of discharging schedules. Requirements deficiency and disparities and the discussion on the control authority show constraining effects on the conditions for pilot projects. Realistic pilot conditions are shown to be essential for scaling V2G activities, and pilot projects are considered vital for exploring the possibilities of V2G technology. However, lacking conditions obstruct the development of definitive V2G configurations and designs necessary for large-scale diffusion. This study has shown two chicken-and-egg dilemmas play a significant role in the slow adoption of V2G. Niche actors are awaiting each other to continue their research and development activities. EV manufacturers demand V2G-compatible EV supply equipment (EVSE) to experiment with V2G technology, while EVSE manufacturers and CPOs await V2G-compatible EVs. Moreover, niche actors await definitive technical standards, while standardisation organisations and regulators are reliant on insights retrieved from practical experimentation to develop effective standards and regulations. These dynamics require a coordinated approach to empower and stabilise the development of V2G technology and enable widespread diffusion. Niche actors should be at the front of the developments, so active involvement with standardisation and requirement-setting is advised. Besides, collaborations between niche actors across Europe should be stimulated to prevent market fragmentation and segmentation, since these effects are detrimental to all V2G actors and the system in general. Therefore, the barriers identified pose a significant influence on pilot conditions, constraining experimentation, implementation, and the overall development of V2G technology.

The Green Deal (Fetting, 2020), initiated by the European Commission, aims to reduce greenhouse gas emissions within the EU to limit global warming to 1.5 degrees Celsius compared to pre-industrial levels (International Panel of Climate Change, 2022). The EU focuses on energy that is acceptable, applicable, available, and affordable – referring to sustainability, technological readiness, energy security, and cost-effectiveness. Energy security involves meeting energy needs using domestic sources to avoid reliance on imported energy, which could pose threats to energy security due to the political power of supplying countries (Asia Pacific Energy Research Centre, 2007). A potential proposed by researchers is the Desertec project (Van Wijk & Wouters, 2021).

In this idea the strong solar radiation in African countries is used to supply Europe with hydrogen The Desertec project, despite its promising potential, never materialized. Studies examining the reasons for its non-realization concur that the primary hindrance was not technological limitations but rather the complexities arising from multi-country politics (Schmitt, 2018; Scheer, 2012; Lilliestam & Ellenbeck, 2011). Scheer (2012) aptly described the plan as "practically impossible for obvious political, economic, and sociological reasons" (Schmitt, 2018). He emphasized that coordinating an energy system involving over forty different goverments, each with their own energy grids and territories for power transmission, inevitably led to unrealistic expectations.

In response, this research presents a system that addresses key barriers that impeded the Desertec project's success. By focusing on a specific geographical area with fewer national governments involved, integrated energy grids, and no energy transport crossing other countries' territories, the research proposes a solution to the challenges identified by Scheer (2012) and Schmitt (2018). Portugal and Spain, with an integrated energy grid and limited European energy grid connection, are considered, while Spain's existing natural gas pipelines to Algeria offer a paved path for hydrogen transport. With this more manageable consortium of four national governments and fewer complexities, the research seeks to evaluate various technological design options using a cost model to test their feasibility and impact on energy security. The aim of this research is to provide an answer to: How does a technologically feasible Maghreb-Iberian green hydrogen system (MIGHS) impact the Iberian energy cost and energy security?

The research conducts an analysis of the Dutch day-ahead electricity market prices spanning from 2015 to 2022, examining the relationship between increasing RE penetration and day-ahead electricity price fluctuations. The electricity price fluctuations over this time period are reviewed for patterns and recalculated for inflation corrections that contribute to a surge in electricity prices post-August 2021.

This price volatility is further researched by three energy market phenomena. A part of these price fluctuations can be explained by the presence of the Duck Curve phenomenon in the Dutch market, highlighting challenges associated with limited RE production time and energy demand. The Duck Curve, which illustrates the net load over a 24-hour period, reveals a decrease in fossil energy production during daylight hours and a peak in production during the night. When compared to California, this Dutch Duck Curve is more stable with the incorporation of wind energy, signifying a more reliable and consistent energy supply throughout the day.

Moreover, the study delves into another energy market phenomenon called the merit order effect, where the increased penetration of RE with low marginal cost leads to declining day-ahead electricity prices. The phenomenon is researched through the implementation of an OLS regression analysis. By plotting the results in individual months and years the merit order effect is visualized. The results are showcasing increased volatility, particularly in the latter part of the analyzed period (2020-2022). Fluctuations resembling a Duck Curve are observed, emphasizing the impact of RE implementation on price decline during periods of abundant RE supply.

Additionally, the cannibalization effect phenomenon is addressed where the growing penetration of RE undermines their own economic value. The Unit Revenue and Value Factor are calculated to aid the analysis. Followed up by the Prais-Winsten method to quantify this cannibalization effect. The results are revealing negative correlations between solar and wind shares and Unit Revenue and electricity prices. Thus, as RE penetration increases, electricity prices decrease, underscoring the cannibalization effect's influence on price fluctuations.

In conclusion, this study offers insights into the dynamic transformation of the Dutch electricity market. The identification of key phenomena such as the Duck Curve, the merit order effect, and the cannibalization effect provides empirical evidence of the market's evolution. These findings underscore the critical need for strategic management, targeted interventions, and innovative solutions. It is imperative to navigate these changes effectively to facilitate the ongoing expansion of renewable energy technologies while upholding the stability and competitiveness of the electricity market.

 A climate change mitigation strategy seen in the maritime sector is the electrification of berths through implementing shore power installations. The incorporation of grid-connected battery energy storage systems (BESS) into shore power installations, thereby creating hybrid installations, potentially accelerates the implementation of shore power. According to a gap in literature, this research evaluates the potential of various BESS to enhance the economic viability of shore power projects in the portal area in Rotterdam by prioritising consumer energy arbitrage and also trading on the day-ahead market, which is referred to as wholesale energy arbitrage.

This research consists of a techno-economic approach of assessing hybrid installations’ economic viability. First, a literature analysis provided insights in the most suitable BESS types for hybrid installations. Then, evaluation of various shore power projects in the port of Rotterdam resulted in the decision to focus on two impacting berths, namely on the Stena Line (SL) and the Cruise Port (CP) terminal. To assess the economic viability of hybrid installations, two models were designed, namely a BESS costs model and an energy management strategy algorithm. Eventually, the economic viability is evaluated by the net present value, the energy efficiency and effectiveness of the various hybrid installations.

This study reveals that none of the hybrid installations are economically feasible in the way they are examined. Nevertheless, it is indicated that lithium iron phosphate batteries are most suitable to enhance the economic viability of hybrid installations due to a high round-trip efficiency and low system costs. The energy demand of the SL terminal is smaller and more frequent compared to the CP terminal, thereby enhancing the potential of the BESS to cycle more often and to create more revenue. The research includes certain assumptions and uncertainties of which the individual impact on the outcome of the research is analysed. Also, potential scenarios ensuring economic viability are presented.

The Paris agreement has set European countries on a path towards decarbonization of the energy market. Due to the high dependence of natural gas in the Netherlands, various challenges will be faced when facing out fossil fuels. The major drawback of RES is that they are non-dispatchable, meaning their output generation fluctuates over time with respect to weather conditions, resulting in a temporal mismatch of supply and demand. In order to allow shifting of non-dispatchable loads, short-term and long-term energy storage is required. The objective of this research was the implementation of a self-sufficient hybrid storage system in energy communities, including renewable energy generation, short-term and long-term energy storage. A simulation was conducted to form a techno-economic analysis of the system. The results from this simulation showed that the minimization of total costs is obtained by minimizing the capacities of the hydrogen system, as these represent the most expensive components of the system, and maximizing the PV generation, as it is the cheapest component throughout the lifetime. However, the results showed very high costs due to the high costs associated with the hydrogen system, which makes these systems with hydrogen storage impossible to compete with traditional fossil fuel sources. The electricity prices for households of the energy coming from the fuel cell can be greater than three times the electricity price of the national grid

The European Green Deal states that it wants to develop 40 GW of electrolyzer capacity by 2030 in North Africa to combat climate change. Using PV power as the primary energy source, a system is designed that can produce green hydrogen and ammonia to investigate how the location and the capacity of the components can be optimized to produce at the lowest possible levelized costs. This way the competitiveness of green hydrogen and ammonia can be examined against hydrogen and ammonia produced using fossil fuels. Incorporating batteries for electricity storage, a salt cavern for hydrogen storage and cryogenic tanks for nitrogen storage, the system is designed to work as flexible as possible to cope with the variations in PV output.

Scaled to an industrial scale output of 200.000 ton-NH3 per year, the resulting LCOH in 2030 will be 1.63 €/kg-H2, and the LCOA will be 0.394 €/kg-NH3. The competitiveness with fossil fuel-based production is dependent on the price of natural gas, which in this case will need to be higher than 3.16 $/MBTu or 12.25 €/MWh (converted using a USD/EUR rate of 0.88 and a conversion factor of 0.29308 MWh/MBTU, and taking into account a carbon price of 100 €/ton-CO2-eq) for green hydrogen to be competitive. For green ammonia to be cheaper, the gas price must be greater than 4.49 $/MBTu or 17.41 €/MWh.

A sensitivity analysis shows that if the CAPEX and OPEX cost of the five most contributing components to the levelized cost would be 50% higher, the LCOH (2.4770 €/kg-H2) and LCOA (0.5817 €/kg-NH3) would still compare favourably to blue hydrogen and ammonia with a natural gas price of 7.71 $/MBTu (29.89 €/MWh) and 9.04 $/MBTu (35.05 €/MWh). By analyzing the operations of the salt cavern, it is discovered that 6.4% of the salt cavern is used from the available capacity of 3300 ton-H2. Even when the necessary yearly output of ammonia is raised 2 or 4 times, the salt cavern uses only 12.7% and 16.8% of the available capacity. Overall this research shows that green hydrogen and ammonia can compete with hydrogen and ammonia produced from fossil fuels in 2030 and that the possibilities of salt cavern storage for hydrogen are greater than expected because a capacity of 250 ton-H2 is enough for a yearly production of 200.000 ton NH3.

Implementing green alternatives in the heavy­-duty mobility market is required to reach the set climate goals of 2050 and decrease greenhouse gas emissions. Refuelling infrastructures based on alternative fuels such as hydrogen are not sufficiently available. This poses a barrier to large scale implementation and investment in new emission­ free heavy-­duty fuel cell vehicles.

Early market value chain configurations and low refuelling station demand levels are researched and evaluated to determine the optimal future strategy decision based on operational decision-making results. A Mixed Integer Linear Programming (MILP) optimisation model is adopted to simulate a small scale hydrogen value chain dominated by hydrogen production directly from wind energy at the wind turbine location. Additionally, a method is proposed to define future demand for two separate end-­user categories at a hydrogen refuelling station. The spatial configuration of the researched infrastructure is based on a ”Hub” and ”Satellite” concept with distributed production locations and demand locations.

With the current market pricing of all value chain components, cost parity with diesel fuel is reached if the total production capacity of the value chain is utilised. Future cost development will result in a lower total cost for hydrogen per kg than the diesel fuel equivalent. The hydrogen refuelling infrastructure based on wind energy is resilient against increased energy price fluctuations by an expected increase in the installed capacity of renewable energy sources. The operational decision ­making process regarding the hydrogen production process is generally independent of the distribution system size, spatial configuration, and type of non­-stationary storage container, taking into account similar demand within a specified time frame. The hydrogen infrastructure project of DUWAAL by HYGRO is used as a basis for the research.

The Hydrogen Heating Studies project in the Green Village at the TU Delft researches the safe application of hydrogen to heat buildings. This study aims to evaluate hydrogen sensor technologies for residential safety, including the determination of the sensor location inside a standard (Dutch) metering cabinet that achieves the fastest response to potentially dangerous leakages of hydrogen gas.
A range of commercially available sensor technologies was assessed to determine their suitability in residential applications. From this analysis on multiple criteria, the thermal conductivity sensors outperformed the other sensor technologies, albeit only by a small margin versus catalytic hydrogen sensors. Furthermore, an experimental study has been carried out by locating seven sensors at different locations inside the metering cabinet. The hydrogen concentrations have been measured in seven different conditions (case studies). It was found that sensors located at the top of the metering cabinet showed the highest concentrations, more specifically, the top-center.
The results of this research also confirmed that the condition of closed ventilation leads to a constant increase of hydrogen concentration in the metering cabinet. This has implications for managing the risks associated with high hydrogen concentration levels because of hydrogen leakage. Air ventilation inside the metering cabinet causes changes in the distribution mechanism, resulting in mixing and distribution of the hydrogen, reducing hydrogen concentrations. With open ventilation, the hydrogen concentration levels to trigger the alarm inside the metering cabinet should be lowered. Based on the results, it is advised to set the alarm to trigger when hydrogen concentration levels reach 5 %LEL. It was also found that, compared to methane, the release of hydrogen gas leads to a more buoyant gas mixture which mixes more easily with the air and rises three times quicker toward the ceiling. Finally, further research on worst-case scenarios is relevant to make specific recommendations for safe and economically feasible residential heating appliances.

The North Sea has significant potential in becoming a green energy hub, due to its remarkable offshore wind potential, and could therefore facilitate the energy transition to a net-zero energy system in Europe in the coming decades. In this transition, hydrogen is also predicted to play a key role, due to its ability to transport and store substantial amounts of energy. Previous studies have shown that for large offshore wind capacities and substantial distances from the shore, transporting the produced energy in the form of molecules (converting the electricity to hydrogen) via dedicated pipelines would be a more cost-effective option than using electricity cables and converting electricity to hydrogen. This transport could be achieved by developing new hydrogen-dedicated infrastructure or reusing existing natural gas pipelines, which is a cost-effective alternative.

This research study aims to determine the potential for repurposing existing gas infrastructure in the North Sea for hydrogen transport, taking into consideration that this infrastructure will still have to transport natural gas to the shore over the coming years. Redirecting an amount of this natural gas to other, neighboring pipelines creates the possibility for existing pipelines to be freed up for hydrogen transportation, and therefore achieve parallel transmission of green hydrogen and natural gas from the Dutch North Sea to the shore. Consequently, the purpose of this thesis project is to examine the geographical, technical, and economic feasibility of large-scale green hydrogen transportation (produced offshore with green energy from wind turbines), with parallel natural gas transport, via new and already existing gas infrastructure in the North Sea, by 2030.

The first aspect to be analyzed was the geographical configuration of such a system. For that purpose, different possible configurations for parallel transport of hydrogen and natural gas via existing North Sea infrastructure were examined. This analysis indicated that the most suitable scenario, considering the projected timeline and current circumstances, would be repurposing the NGT pipeline for 100% hydrogen transportation (produced from offshore wind search areas 7 and 3), and rerouting the natural gas to the NOGAT pipeline. Both NGT and NOGAT pipelines are parts of the North Sea offshore pipeline system, currently transporting natural gas to the Dutch shore. The next part of the study concerned the physical configuration of the hydrogen transportation system. A component analysis was done, highlighting the most suitable components across the entire system configuration, including the offshore hydrogen production by water electrolysis, its compression, and its transportation via the NGT pipeline among others.

Furthermore, a more elaborate analysis was done to determine the project’s technical feasibility, with emphasis being placed on the key aspects of hydrogen compression and transportation, evaluating its flow characteristics and compression requirements. The analysis results showed that transporting hydrogen via the NGT pipeline to the Dutch shore is technically feasible. Based on the analyzed scenario, the maximum hydrogen transport capacity was found to be 7.9 GW, and the total compression capacity 103 MW. During its transportation along the length of the pipeline (253 km), hydrogen experiences a pressure drop of 10.4 bar (65 bar to 55 bar). An economic evaluation of the system was also performed, indicating that the project is feasible from a financial standpoint as well. The LCOH transport for the proposed system, including hydrogen compression and NGT pipeline repurposing costs, was found to be 0.17 €/kg/1000km. The overall conclusion of this study is that reusing existing infrastructure in the North Sea for hydrogen transportation is a physically and technically feasible option, which can be achieved at a competitive cost.

Vopak has the vision to become climate neutral by 2050 (Scope 1 and 2 emissions). Currently, over 99% of its CO2 emissions originate from storage terminal activities. Action must be taken to reduce these emissions by converting the current (fossil fuel-based) generation of electricity to sustainable energy.

This study aims to research how we can develop a methodology to evaluate the cost-effectiveness of an autonomous solar and storage system to electrify Vopak’s storage terminals? The objective of the method is to develop a system that is clean, reliable, autonomous, and payable (cheap). The selected autonomous system comprises a photovoltaic (PV) system, a battery energy storage system (BESS) and a hybrid inverter to satisfy the energy load of the storage terminal.

The developed method is a techno-economic model using three interlinked components. First, a PV model uses meteorological data and specific technical characteristics to simulate different PV systems. Second, based on the cost of different components of the PV system and BESS, a grid-search system selection method is used to determine the lowest-cost sizing of an autonomous PV and battery
system. Third, the sizing of the system is used to calculate the levelized cost of solar plus storage (LCOSS).

The method is evaluated for three selected storage terminals located in different climates. The lowest cost developed system for Vopak Fujairah Horizon terminal (desert climate), which has a LCOSS of 0.33 [$/kWh]. For Vopak Terminal Laurenshaven (maritime climate), a LCOSS of 0.96 [$/kWh] is calculated. Vopak Panama (tropical climate) has a designed system with a LCOSS of 0.53 [$/kWh]. The calculated LCOSS shows that these autonomous systems are not cost-effective, as they are 3 to 14 times more expensive than average energy prices from the grid for the storage terminal locations. A sensitivity analysis of the system costs and the weighted average cost of capital shows that a 50% decrease in battery costs results in a 38% decrease in the LCOSS. Furthermore, a decrease of 2% of the WACC has the same effect as a total system cost reduction of 10%–15%. Ultimately, enabling the system to
use its dumped energy by selling it to the grid shows the most significant reduction in the LCOSS.

This study clarifies that the cost-effectiveness of an autonomous PV and battery system strongly depends on the climate and seasonal variation of the location as it affects the energy yield of the PV-generating technology and the sizing of the system. Furthermore, the battery system costs are currently two to three times more expensive than a PV system; therefore, to size the lowest-cost system, the sizing strategy rather increases the (cheaper) PV system size to satisfy the load than install an additional battery. This results in oversized PV systems generating a large amount of unused energy. A solution is to enable the system to sell its unused electricity to the grid. An alternative solution would be to add a secondary “clean” energy source, such as a hydrogen generator, to combat these oversized systems and thus reduce the lifetime system costs.

The maritime sector plays an important role in energy transition because offshore vessels are used for building offshore renewables but also have high emissions. The European Union (EU) has determined that from 2025 the maritime sector must pay per ton of CO2 emission. Heerema Marine Contractors (HMC) is an essential player in the maritime sector and plans to have reduced its emissions by 50% by 2025. This thesis aims to build a model in which different emission-abating options can be compared on financial and technical aspects to determine the best roadmap to achieve sustainability.
To do this properly, literature research is done on emissions-abating fuels and technologies/processes applicable to offshore crane vessels. Five sub-questions are answered to find an answer to the main research question:
What will be the future energy configuration of the Heerema fleet and the most technical and financial feasible roadmap to meet the sustainability goals look like?

• What are an offshore crane vessel's main operational energy-consuming modes?

• Which fuel switches and blends are technically and financially feasible, and what are the key characteristics of these fuels?

• What are the key characteristics of the ship-based emission-abating technologies like batteries and carbon capture and storage?

• What are the current vessel-specific levelized cost of Energy (LCOE) and levelized cost of carbon abatement (LCoCA) of the fuel switches and technologies, and how are they expected to develop over time?

• Which emission-abating future scenarios are technically and financially feasible, and how will these sustainable roadmaps look?

With the evaluation of the answers to these sub-questions, the importance of using hydrotreated vegetable oil (HVO) is shown until e-fuels are available. From 2026 e-fuels are assumed to be wide available for usage on board the three vessels, the Sleipnir, Aegir and Thialf the vessels within the scope. The financial evaluation of the e-fuels is in favour of ammonia. The technical evaluation is based on the limited available storage volume favour for methanol.
These findings result in a roadmap using batteries on board the vessels together with HVO as fuel and when available installing designated ammonia or methanol tanks, and using ammonia or methanol as a 100% fuel blend in the internal combustion engines of the three vessels.

Since the European Commission concluded that green hydrogen is a key priority in the achievement of Europe’s energy transition, hydrogen is included in transition strategies of many parties. The Netherlands has the ambition to become the European leader of hydrogen deployment within their strategy. The oversea import of hydrogen is highly needed in the future, as it is expected that NW-Europe does not have sufficient renewable energy sources to locally produce the entire hydrogen demand. Due to the extensive gas network and distribution infrastructure, the strategic location of Rotterdam has the potential to become the new hydrogen energy import hub of Europe. As Vopak, world’s leading independent tank storage company, sees opportunities in the large scale import and storage of hydrogen, an evaluation of the entire green liquid hydrogen supply chain is done. In this paper, an evaluation of the green liquid hydrogen supply chain is presented. The literature review of the individual elements led to the construction of the supply chain existing of the consecutive elements: renewable energy generation, electrolyser technology, liquefaction plant, onshore storage, oversea shipping, onshore storage, distribution of hydrogen and consumption by end-users. Within this supply chain, liquid
hydrogen is taken into account due to its favorable volumetric density of 70.8kg/m3. This results in the handling and storage of hydrogen at cryogenic conditions: 20K at a pressure of 1.1 bar. The scope of the project is determined to be from the liquefaction plant to the distribution of the hydrogen into the different transportation modes on the importing terminal. A technical and economic model is created in order to analyse different throughput scenarios. These scenarios transport the hydrogen from a country X in which abundant renewable feedstocks are expected to be produced to the importing location of Rotterdam. By creating and merging a technical and economic model, an in-depth research is conducted. The model determines optimized configurations and their sensitivity for certain throughput scenarios. The technical research led to the following findings: 1. The storage tank has an expected maximal spherical capacity of 40 000m3 with an according BOR of 0.043%/day. If higher capacities are required, the shape
of the tank shifts towards cylindrical structures, due to the vacuum insulation technique. Whenever this capacity is increased, the currently used technology of vacuum MLI is expected to shift towards membrane technology. This is due to that vacuum insulation is not applicable to flat surfaces unless a very thick inner wall is constructed. The exact technology and according BOR of membrane technology is highly proprietary. 2. The liquefaction plant is a mature technology of which the capacity can be easily increased. The current largest plant capacities can be increased from 50tpd to 500tpd, due to easily transportable cold boxes. The current energy consumption of 8kWh/kg can presumably decreased to around 6kWh/kg. Although the minimum capacity of a plant is 20%, the energy consumption is heavily affected. 3. The first oversea LH2 vessel, with a capacity of 1250m3, is currently in its sea trials. Concept designs and interviews led to the perspective that a LH2 vessel of 100 000m3 can be expected in the year 2030. 4. The BOP systems do not exist on industrial scale. Although the handling systems do not exist, the transfer loss during a transfer of a parcel is estimated to be 1.5%. 5. The energy consumption throughout the supply chain shows that the liquefaction plant plays a dominant role. The second most energy intensive process is the oversea shipping. The economic simulations led to the following findings: 1. The LCOH in Rotterdam can decrease to 2.78USD/ kg when a throughput scenario of 3.5Mt/year from the location of Saudi Arabia is realised. 2. The competitiveness tipping point (3.15USD/kg) from the location of Morocco and Saudi Arabia is around 0.35Mt/year. 3. Australia does not reach an economically attractive liquid hydrogen oversea supply chain to Europe, unless the demand highly increases. 4. In small throughput scenarios the storage tank has the most dominant impact on the LCOH. This is due to that the liquefaction plant and ship are scalable to a single unit, while the storage tank has a minimum of three tanks per terminal. The combination of the technical and economic results led to an overall conclusion that a green liquid hydrogen supply chain is economically competitive at a throughput scenario of 0.31Mt/year from Morocco. Although the technical elements within this scenario are currently still in concept phase, expectations look very promising and can be deployed by 2030. Further BOP and handling systems are not yet commercially available, similar expectations are set for the year 2030. Whenever the hydrogen demand in NW-Europe increases, an acceleration of the oversea hydrogen deployment is established. Therefore further research needs to keep a close eye on the technical development of the supply chain.