Grid congestion has become a structural constraint on the Dutch energy transition, yet the flexible grid connection agreements introduced to facilitate Battery Energy Storage Systems (BESS) under congested conditions remain poorly understood as integrated institutional arrangements. While these agreements are intended to unlock network capacity through non-firm access, they also create an institutional paradox: the technologies best suited to alleviate congestion are increasingly constrained by access arrangements originally designed for passive network users. This thesis investigates how the institutional design of flexible connection agreements influences the financial viability, operational behaviour, and system alignment of utility-scale BESS in the Netherlands.

An exploratory sequential research design is adopted, combining qualitative institutional analysis with quantitative policy evaluation. First, 33 Dutch regulatory and stakeholder documents are analysed to identify recurring institutional frictions, which are synthesised into three structural tensions: temporal misalignment, asymmetric risk and value allocation, and a disconnect between operational control and financial responsibility. These tensions are subsequently operationalised as four contractual design properties: compensation structure, firmness, volume orientation, and directive control. Their effects are evaluated using a Mixed-Integer Linear Programming (MILP) Policy Testbed that simulates the operation of a 10 MW / 20 MWh utility-scale BESS across 200 independent Monte Carlo market realisations. The evaluation covers four existing Dutch flexible connection agreements, the Alternative Transport Right (ATR85), Capacity Limiting Contract (CBC), Capacity Steering Contract (CSC), and Time-Based Transport Right (TBTR), together with two prospective contract designs, Volume Bound and Firmness Gradient, developed to isolate the independent effects of individual contractual properties.

The results demonstrate that the principal barrier to battery bankability lies upstream of contract design itself. The high-voltage transport tariff alone absorbs approximately 70% of gross market revenues, rendering the unconstrained benchmark structurally non-bankable. Among the evaluated agreements, only the Capacity Limiting Contract consistently restores financial viability. However, it achieves this through a compensation coverage ratio of up to 1,596% of demonstrated operational risk, indicating that bankability is restored through financial transfers sufficiently large to offset the underlying tariff burden rather than through proportionate risk compensation. By contrast, fixed tariff-discount arrangements, particularly the Time-Based Transport Right, remain financially unviable because rigid transport windows conflict with high-value market opportunities.

Beyond financial performance, no single contractual design property simultaneously optimises all evaluation dimensions. Directive control, implemented through the Capacity Steering Contract, delivers the strongest congestion alignment but depends critically on accurate DSO forecasting and activation timing. Volume-oriented arrangements reduce battery degradation and extend operational lifetime, while their contribution to congestion management is regime dependent, improving outcomes in urban, demand-driven networks but potentially worsening them in rural, generation-driven systems. Overall, the findings demonstrate that the effectiveness of flexible connection agreements is determined by their underlying design properties rather than by contractual labels alone. More fundamentally, they indicate that existing agreements are compensating for structural shortcomings in the Dutch grid tariff architecture, suggesting that the greatest opportunity for future reform lies in grid-access pricing rather than incremental contract redesign. ... Read more

The rapid electrification of industry, transport, and the built environment is increasing the pressure on Dutch distribution grids. As a result, grid congestion has emerged as a major constraint on economic development and renewable energy integration, while network reinforcement projects often require substantial investments and long implementation times. Local energy hubs, in which companies collectively coordinate local generation, storage, and demand within a shared grid connection, are increasingly recognised as a promising approach to relieve this pressure. However, while the potential of energy hubs is widely acknowledged, a systematic techno-economic comparison with conventional grid reinforcement remains absent from the scientific literature. This creates challenges for policymakers, distribution system operators, and hub participants seeking to make informed investment decisions. This thesis therefore asks: which configurations of a local energy hub provide a technically and economically viable alternative to conventional grid reinforcement for industrial areas located in congested regions of the Netherlands? To answer this question, an agent-based model was developed in NetLogo that simulates a heterogeneous group of industrial companies operating under a shared Group Transport Agreement. Each company is assigned a sector-specific demand profile, with solar PV, wind, battery storage, and EV charging evaluated over a full simulated year. A coupled cost model in Microsoft Excel translates the technical outcomes into normalised costs per megawatt of additional contracted capacity, enabling direct comparison against grid reinforcement costs derived from the investment plans of grid operators. The results show that energy hubs can provide a technically and economically viable alternative to conventional grid reinforcement, with the best configurations costing roughly half the price of grid reinforcement per megawatt of additional contracted capacity, and no configuration exceeding 2.2 times the cost. The strongest argument for energy hubs, however, is not cost but time: whereas grid reinforcement takes ten to fifteen years, a hub can be operational within roughly two years, making speed the most valuable property of all in the current congestion situation. Energy hubs and grid reinforcement are best understood as complementary rather than competing solutions: hubs can unlock capacity now for the companies that cannot wait, while grid reinforcement remains essential to build the long-term infrastructure for large scale renewables that local coordination alone cannot provide. ... Read more

Green hydrogen is expected to play an important role in achieving EU climate neutrality, particularly in decarbonising hard-to-abate industrial sectors. As Dutch domestic renewable hydrogen production is expected to be insufficient, large-scale imports will be essential. Brazil has emerged as a promising supplier due to its abundant renewable electricity, favourable policy environment and growing pipeline of export-oriented green hydrogen projects. Within this context, the Pecém–Rotterdam corridor is among the more developed overseas hydrogen corridor initiatives, yet no operational supply chain has materialised and most projects remain before final investment decision.

This thesis examines how transition barriers shape the early-stage development of the Pecém–Rotterdam green hydrogen corridor. It addresses a gap in existing research, which often focuses on national hydrogen systems, regional value chains or isolated value-chain segments, while the interaction between exporting and importing regions remains underexplored. The study uses an exploratory embedded qualitative single-case design, combining Industry Life Cycle theory with the transition-failure framework to locate the corridor in an early market phase and diagnose the barriers preventing a first operational chain. The empirical basis consists of academic and grey literature, complemented by thirteen semi-structured interviews across seven stakeholder groups.

The findings show that the corridor is largely technically feasible, as ammonia, methanol and hydrogen are already produced, transported and traded globally. However, large-scale reconversion technologies such as ammonia cracking and methanol reforming remain immature, costly and energy-intensive, making direct carrier use more attractive in the short term. Sixteen barriers were identified and grouped into four clusters: market formation, the institutional and regulatory environment, infrastructure and production capability, and coordination and shared directional vision. The most binding barriers are the cost gap with fossil alternatives, weak and uncertain demand, regulatory uncertainty, limited subsidy budgets, and coordination complexities. Together, these barriers form a self-reinforcing bankability loop in which producers, offtakers, infrastructure developers and governments each wait for other actors to move first.

The study further finds that barriers differ across the corridor. Pecém mainly faces physical and operational constraints, including grid congestion and shared-infrastructure development, while Rotterdam faces more institutional and strategic barriers, including permitting complexity, public concerns around ammonia handling and tensions between climate ambition and industrial competitiveness. The main bottleneck lies on the European demand side, as Pecém’s development depends on credible long-term offtake from Europe.

The thesis contributes by analysing Pecém–Rotterdam as one integrated end-to-end socio-technical system and by adapting the transition-failure framework to an early-stage corridor context. It concludes that the corridor is not blocked by individual problems, but by mutually reinforcing uncertainties. Breaking this deadlock requires a predictable green premium, long-term regulatory certainty, bankable offtake, import-compatible public financing and coordinated chain commitment. A public-private corridor consortium focused on a small-scale demonstration chain could help reduce uncertainty, generate learning and build confidence for gradual scale-up.
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The Dutch energy transition is producing structural grid congestion, national and regional, and renewing the question of how the country's extensive gas infrastructure should be used. Power-to-methane (P2M) converts surplus electricity and captured CO2 into e-methane, a low-carbon gas that can replace fossil natural gas in the existing network. Despite that infrastructural advantage, it has remained underexplored. This thesis asks: Under which technical, infrastructural, and socio-technical conditions can power-to-methane create system and societal value in a regional energy system in the Netherlands?

Power-to-hydrogen (P2H), the closest comparable pathway, serves as the benchmark for P2M's distinctive value throughout. The analysis runs through four sub-questions, from reactor performance to societal value. A mass-energy balance model characterises two operational modes: an electricity-driven mode, intermittent around surplus periods, and a CO2-driven mode, continuous on stable point-source streams. The infrastructural analysis places deployment at cluster-adjacent and biogenic sites where electricity, CO2 and gas align in both location and timing, with industrial CO2 access narrowing toward 2030. A multi-criteria comparison shows P2M's constraints differ in kind from P2H's: its most prominent, recognition, can be addressed on shorter timelines, where P2H's depend on system change over decades.

P2M's distinctive societal value comes from two structural drivers. Driver 1 is the climate value of integrating CO2 that would otherwise be emitted and replacing fossil methane downstream: about EUR 49k/MW/y in the electricity-driven mode and EUR 168k/MW/y in the CO2-driven mode at central ETS pricing. Driver 2 is the system-wide cost of building a new hydrogen network instead of reusing the existing gas system: tens of billions nationally and tens to hundreds of millions per cluster regionally, against P2M's own cost of a single 10 MW methanation-and-injection installation of EUR 7–11 million. The flexibility P2M is often credited with is valuable, but does not set it apart: P2H and batteries do the same.

To realise the full value, both drivers must deliver at the same site, and the two are never aggregated. The reason is the distribution of that value: Driver 1 reaches the public and the state, and in part the CO2-supplying industry; Driver 2 reaches network users, the state and industry. Only when both deliver does the value reach across society; where only one does, P2M loses its edge. The case holds across most of the four II3050 scenarios, weakest in the hydrogen-dominant one.

What stands between P2M and that value is neither the technology nor the infrastructure. It is whether e-methane is recognised as a gas-grid option in the national decisions now shaping the 2030 to 2040 system, where it does not yet appear. The risk for P2M is omission, not rejection. Each year it stays outside the frame, more CO2 goes to storage and more of the system to hydrogen, leaving less room for it. P2M is technically workable and its value identifiable, but it is unbuilt and, in policy, unrecognised. What remains is to act on it while the system is still being decided, before a means that fits is left unused.

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This research investigated the relation of multiple factors on the chance for the successful implementation of systems that allow for the shared use of power transport capacity among multiple users. The shift from individually issued power transport capacity to a shared capacity allows for a more efficient usage of the existing power grid. This shared system has the potential to reduce the experienced grid congestion. Despite the benefits these systems can provide, they are implemented in only a few locations.

A scoping literature review was performed and 5 interviews with actors involved in shared power transport capacity pilot projects were conducted. The obtained data in combination with any sources regarding the implementation process of relevant pilot projects was used in a qualitative comparative analysis. The analysis showed four factors necessary for success in all situations as well as four different situations in which different combinations of other factors could result in success. While the sample size was too small to yield results that could be fully validated, a clear distinction between the various situations was identified and the required combination of factors could be explained based on the corresponding cases. ... Read more

This research aims to explore the behavioural diversity and bounded rationality within an Energy Hub (EH) under congestion management with a modelling tool such as Agent-Based Modelling (ABM). The model incorporated rotational load shedding, adaptive capacity allocation, PV panels, and a dashboard. The model also incorporated behavioural drivers, such as the symbiosis of participants with different Social Value Orientations (SVO) and other factors that influences load shifting. The ABM was compared with real-world data of participants in an EH. The results show that altruistic and pro-social populations perform the best in short-term, while the competitive populations adapt over time in long-term. Gamification could be a strategy to use the social factors to engage diverse participants in interactive activities and support collaboration. Time-of-Use (ToU) pricing could be a strategy to add next to the dashboard to engage diverse competitive and individualistic participants to load shift. Proportional load shedding could be another strategy to provide for a more equitable way to load shedding. This study provides a system-level perspective, showing how heterogenous and homogenous IC compositions influence demand response outcomes. This model can be used in future case studies to analyse collaboration patterns, test interventions, and the recommended strategies. ... Read more

The development of hydrogen import value chains is considered essential to achieving long-term decarbonization goals in the Netherlands. Although the systemic complexity of international hydrogen trade is acknowledged in the literature, empirical research into the policy and governance aspects of these import chains remains limited in the Dutch context. This study examines the extent to which current Dutch and EU policy frameworks address the challenges associated with early-stage hydrogen import chains, drawing on case studies of the United Kingdom (non-EU, non-EEA) and Norway (non-EU, EEA).

A qualitative case study approach was employed, combining policy document analysis with 18 semi-structured stakeholder interviews from various sectors, including industry, infrastructure, research institutions, and government-affiliated organizations. The qualitative data were coded and analyzed using Atlas.ti, with categories of transition challenges based on the frameworks of Weber et al. (2012) and bolhuis (2024), which were used to structure the findings.

The analysis reveals a range of interdependent challenges, including regulatory complexity, infrastructure bottlenecks, limited financial support for ammonia cracking, and a lack of tailored safety frameworks. Nevertheless, some instruments, most notably H2Global and the RED III RFNBO mandates, are positively received by stakeholders and viewed as promising instruments to stimulate investment and demand. Their full potential, however, depends on timely implementation, increased scale, and improved alignment across national and European levels. Variation in national export contexts further shapes the character of the challenges: in the UK, regulatory divergence and uncertainty surrounding export subsidies are key constraints; in Norway, more substantial institutional alignment is offset by public concerns surrounding the use of ammonia.

Enhancing the current Dutch policy framework through an updated national import strategy, robust and clear demand articulation, infrastructure development, and targeted policy for green ammonia imports would improve investor confidence and facilitate the timely development of international hydrogen import chains.
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The energy transition is transforming electricity distribution networks, leading to increased congestion due to the rapid integration of decentralized renewable energy sources (RES) and electrification of demand. In this context, real-time congestion management (RTCM) is becoming essential. Aggregators, parties that coordinate distributed energy resources (DERs), are recognized as key enablers of RTCM due to their ability to dynamically shift load and respond to local grid conditions. However, current institutional and operational frameworks often fail to support their effective participation.

This thesis investigates how aggregator-based flexibility can be effectively activated and utilized for RTCM in distribution networks. Combining a literature review with expert interviews, the study identifies key design uncertainties, behavioural dynamics, and institutional barriers that currently hinder aggregator participation. These insights are synthesized into a functional coordination framework, outlining six core system functions required for effective RTCM, such as real-time communication, technical validation, transparent activation logic, and feedback mechanisms.

In parallel, a cost benchmark model is developed to estimate the financial bandwidth within which real-time activation strategies must operate. The model uses historical market data from aFRR and curtailment to evaluate the cost-effectiveness of flexibility deployment. Applied to the Dordtsche Kil region in the Netherlands, the simulation reveals that targeted real-time activation can significantly reduce average activation costs, but introduces exposure to price volatility.

The findings underscore that real-time flexibility deployment is not only a technical challenge but also an institutional and behavioural one. Key barriers identified include limited access to real-time grid data, the role of Balance Responsible Parties (BRPs), and lack of predictable compensation. These barriers foster risk-averse strategies among aggregators, reducing participation in existing mechanisms.

The study concludes that RTCM requires more than price signals or market access: it demands a robust system architecture that aligns technical feasibility with institutional rules and behavioural incentives. The proposed framework and benchmark model provide DSOs and policymakers with actionable tools to design and evaluate RTCM mechanisms. Recommendations include piloting the coordination framework in congested areas, investing in digital infrastructure (e.g., APIs and dashboards), and addressing BRP-related constraints through policy reforms.

Ultimately, this research contributes to the academic and societal discourse by proposing a structured, interdisciplinary approach to enabling aggregator-based flexibility in real-time distribution grid operations, thus supporting a more reliable, cost-efficient, and sustainable energy system. ... Read more

The Dutch electricity grid is increasingly facing challenges due to grid congestion. If left unaddressed, this could eventually lead to electricity supply disruptions, significant economic losses, and a decline in living standards. In response, the Netherlands Authority for Consumers and Markets (ACM) has proposed the introduction of injection charges for large-scale electricity producers as a potential solution to incentivize more efficient use of the existing grid infrastructure.

This study evaluates the effects of different injection charge designs on grid load and the resulting need for network reinforcement. The results were obtained by constructing a network model based on the electricity network topology of the municipality of Reimerswaal in the Netherlands. The model incorporated generation technologies such as onshore wind and solar PV, and applied a priority dispatch policy that favors local renewable electricity generation over imports from elsewhere.

In total, four injection charge variants were assessed. These include a uniform tariff based on the kWcontract and kWmax charge components, a time-dependent tariff on the same components, a uniform tariff based on kWh, and a combined variant incorporating time-dependent kWcontract and kWmax charges along with a uniform kWh tariff.

Results show that peak grid loads can be reduced by up to 35.55% when using time-dependent tariffs based on the kWcontract and kWmax components. These variants also proved more effective at reducing peak occurrences than uniform, non-time-based tariffs. While the uniform kWh-based variant marginally decreased import-related peak loads by up to 0.99%, it had no effect on injection-related peaks, making its overall impact rather limited. The combined variant yielded results similar to those of its individual components, combining injection-related peak reduction with a marginal decrease in import-related peaks.

These findings indicate that well-designed injection charges can effectively reduce peak grid load and mitigate the need for network reinforcement. However, their effectiveness depends on the specific charge design and local grid conditions. In addition, the design and implementation of such charges require careful consideration of factors beyond technical efficacy. Legitimacy, feasibility, stakeholder support, and potential economic and environmental implications must also be taken into account. ... Read more

Offshore wind energy in the North Sea is central to Europe’s energy transition, yet development is slowing amid rising complexity and systemic strain. This thesis investigates the root causes of this stagnation using a systems thinking approach—combining literature review, stakeholder interviews, a Current Reality Tree (CRT), and a Causal Loop Diagram (CLD). The analysis identifies three interconnected systemic causes: Fragmented Energy Governance, Historical Policy Dependence, and Uncoordinated Value Chain Expansion. These factors manifest in permitting delays, financial uncertainty, and supply chain vulnerabilities that reinforce a cycle of underinvestment and delayed deployment. Offshore wind development is categorized across the value chain, financial structure, and global supply network to capture the sector’s evolution and current bottlenecks. Current policy efforts remain insufficient and reactive. To overcome stagnation, the study recommends coordinated interventions: harmonized permitting, accelerated infrastructure investment, inflation-proof financing, and domestic supply chain strengthening. These strategies aim to reverse negative feedback loops and re-enable sustainable growth, securing the North Sea’s role in Europe’s renewable energy future. ... Read more

The Dutch energy system is rapidly transforming due to electrification, decentralization, and renewable integration, causing widespread grid congestion. While grid reinforcement is slow and costly, Multi-Carrier Energy Hubs (MCEHs) are increasingly promoted as flexible, localized alternatives. These hubs, situated on industrial estates, coordinate electricity, heat, and potentially hydrogen to reduce reliance on transmission infrastructure. However, current evaluation methods of MCEHs are focused on short term feasibility and stakeholder-driven, often ignoring long-term societal impacts.
This research introduces the concept of structural societal value—the enduring economic, environmental, and social benefits of an energy hub beyond short-term congestion relief. Using a societal cost-benefit approach (MKBA) integrated with expert interviews and a custom-built energy flow model, the study evaluates MCEHs not only against grid reinforcement but also in terms of broader system outcomes. A case study of the Tholen industrial estate illustrates this approach in practice.
Results show that MCEHs offer temporary relief when congestion costs are high and reinforcements delayed. However, their structural value depends on local load profiles, flexibility needs, and renewable integration potential. By evaluating MCEHs through a consistent, criteria-based framework, decision-makers can determine whether a hub should remain temporary or evolve into a long-term solution. The findings stress the need for transparent trade-offs between hubs and traditional infrastructure, supporting more informed, adaptive energy planning.
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This study investigates the design of a hydrogen transport infrastructure connecting North Africa and Europe, with a focus on balancing economic cost-efficiency and system robustness, taking into account potential geopolitical instability. Given the increasing relevance of green hydrogen in the European energy transition, the study addresses the need for a methodologically sound approach to evaluate large-scale infrastructure under geopolitical constraints. A novel combination of network reduction techniques—including Steiner-based pruning and Girvan–Newman clustering—was developed to make extensive pipeline datasets compatible with the Optimal Network Layout Tool (ONLT), enabling the computation of near-optimal pipeline layouts. The model incorporates an improved cost function that distinguishes between new pipeline construction, repurposing, and reinforcement. Using this setup, multiple geopolitical and infrastructural scenarios were simulated to test network performance under stress. Results show that while a tree-based infrastructure provides cost minimization, it introduces structural vulnerability in the face of supply shocks or sabotage. Redundancy through selective reinforcements and routing diversification enhances resilience at a modest cost. The study offers a methodological framework and policy-relevant insights for planning hydrogen infrastructure that is both economically viable and geopolitically robust. ... Read more

The increasingly integrated renewable energy sources have a strong intermittency in electricity supply, resulting in increasing mismatches between electricity supply and demand. This has led to an increase in imbalances in the electricity grid, heightening the need for regulating power, such as flexible assets. Currently, the balancing markets are experiencing a high volatility in system imbalance and imbalance prices, resulting in market and system instability.

Previous studies have largely focused on how renewable energy sources lead to an increase in system imbalance and have stressed the need for flexible assets. Furthermore, several studies show that flexible assets can make significant profits in today's balancing markets by optimising their implicit balancing strategy. However, little attention has been devoted to the price incentives provided by the different pricing designs in the EU and how their remuneration structure affects the implicit balancing behaviour of flexible assets. As flexible assets are increasingly deployed on the balancing market, any strategic or gaming behaviour might have a significant negative impact on grid stability and system costs. Therefore, this research aims to answer the following research question:

What implicit balancing behaviour do flexible assets show in different imbalance settlement designs and what balancing market design recommendations can be provided based on this?

This research question is explored using mainly a quantitative approach. First, a literature review on European balancing markets is provided, explaining how the EU Balancing Guideline forms a framework for the balancing markets in EU. Furthermore, the balancing markets in the Netherlands and Belgium, which serve as case studies in the modelling, are explored in detail. Then, two linear optimisation models are developed to simulate the balancing markets of both countries and to show how the price incentives provided by the markets influence the behaviour of a flexible asset that aims to optimise its profit. Additionally, the impact of the asset's implicit balancing, following three different strategies, on imbalance prices and the asset's own profit is examined. A comparison is made between the results under the two different pricing designs, showing how different design choices affect the opportunities for strategic behaviour and potential market exploitation. The main insights obtained can be summarised as follows:

- A flexible asset can, under certain circumstances, exploit the market with gaming behaviour, in which it intentionally amplifies the imbalance price and thereby enlarges its own profit.
- Marginal pricing, provides a larger opportunity window for strategic and gaming behaviour compared to the averaging of marginal prices. Establishing the imbalance price based on the average of all marginal prices during an ISP can mitigate the asset's effect on the imbalance price, but can eventually not prevent extreme imbalance prices either.
- There are advantages and disadvantages to both single and dual pricing. Single pricing provides a more stable pricing system, but is limited in discouraging overreactive implicit balancing. The dual pricing design discourages overreactive balancing stronger, but this can lead to great losses for BRPs, increasing their financial risks, and can decrease market stability.
- The volume of the system imbalance plays an important role; in ISP with lower system imbalances, flexible assets can only increase the imbalance price to a very limited extend, before a market saturation point is reached where all system imbalance is balanced implicitly. With higher system imbalances, flexible assets can push the imbalance price to much higher, or even extreme values.

As balancing markets evolve with increasing volatility in system imbalances and higher volumes of flexible assets, transaction costs are expected to rise due to higher levels of market participation, growing complexity in forecasting, and potential market saturation effects in quarter-hours with lower system imbalances. These expectations for future conditions emphasise the need for pricing designs that ensure grid stability and market efficiency. Therefore, this research provides several recommendations:


- TSOs should consider re-evaluating the overall pricing design for FRR and imbalance. These two pricing designs are highly interconnected, as imbalance prices should reflect the costs made for FRR. Marginal pricing has both advantages and disadvantages, as it can reduce strategic bidding for FRR, but can reward gaming behaviour in implicit balancing, leading to market instability. A different pricing design might provide a more stable market, where strategic implicit balancing is discouraged.
- The choice between single and dual pricing needs to be carefully considered. Based on this research's findings, single pricing leads to less risks for BRPs and contributes to market stability. However, additional research into the decision-making process of flexible assets under the risks present in both pricing designs is needed to be able to make a stronger recommendation.
- Adjusting other market design variables could help reduce volatility, such as loosening FRR qualification requirements to encourage flexible assets to provide FRR instead of implicit balancing and reducing the ISP to five minutes. Yet, further research is needed to assess the full implications of adjusting these design choices.

The findings presented by this research contribute to current efforts to improve balancing market designs, by showing that both pricing designs have vulnerabilities that allow flexible assets to exploit the market under certain circumstances, which is inconsistent with the objectives of the balancing market. The discussed design choices and future research recommendations contribute to improving balancing markets, to regain grid stability and market efficiency.

However, there are some limitations to consider. The model contains significant simplifications, such as the aggregation of multiple flexible assets into a single asset, which does not fully capture the decision-making process of multiple individual actors with a flexible asset in the real world. Additionally, the assumption that the flexible asset has perfect information and foresight does not correspond to reality. Furthermore, the heuristic optimisation method used may not always produce the optimal strategy for the flexible asset. Based on these limitations, several suggestions for future research are made. For example, using a bi-level optimisation method might provide more refined results of the asset's strategic behaviour. Future research could also consider the wider context of the market, such as how imbalance pricing influences the decision-making processes of numerous BRPs acting simultaneously, without perfect or with limited market information. An analysis from a game-theoretic point of view, showing the interactions among various actors, might lead to more refined or different outcomes when the different pricing designs are compared. ... Read more

DSOs are of vital importance for the resilience and adaptivity of the essential energy grids with continuously growing demand and consistently increasing complexity. Additionally, a substantial amount of energy technologies that are needed for the transition are still in the demonstration or prototype phase. The increasing pressure on DSOs to adapt to a plethora of fundamental challenges necessitates innovative frameworks to support sustainable development. This study set out to develop a new framework for guiding DSO innovation efforts with three key objectives: take into account the system context, provide tangible and actionable output and consider the regulatory environment. The framework was abductively constructed through a synthesis of five established innovation models and refined using expert interviews and case studies. The resulting diagnostic framework distinguishes three parallel levels for innovation: the project level, company level and ecosystem level. Each with their own respective more detailed factors. Another contribution of this research is the introduction of strategic alignment as a systemic factor in innovation in the literature. This research represents the first exploration of an innovation framework that holistically addresses the unique complexities and demands of DSOs, offering a foundation for further refinement and application. ... Read more

The transition towards a decarbonised electricity system presents significant challenges for the Dutch electricity market, particularly regarding the integration of renewable energy sources and the mitigation of grid congestion. Flexibility is increasingly recognised as a crucial tool for optimising grid utilisation, reducing reliance on infrastructure expansion, and enabling the integration of new energy users. However, despite its technical feasibility, the adoption of flexibility measures remains limited due to a combination of regulatory, market, and behavioural barriers.

This study examines the factors influencing the decision-making of large electricity consumers in the Netherlands regarding the adoption and utilisation of flexibility options. Using Transaction Cost Economics (TCE) as a theoretical framework, the research identifies key barriers, including high transaction costs, regulatory uncertainty, contractual complexity, and economic disincentives. A qualitative methodology was applied, incorporating a literature review, policy analysis, and semi-structured interviews with industry experts.

The findings reveal that flexibility adoption is constrained by two primary challenges: some stakeholders are willing but unable to provide flexibility due to external constraints such as grid congestion and infrastructure limitations, while others are able but unwilling due to financial concerns, operational risks, and misaligned incentives. High transaction costs—resulting from information asymmetry, contractual uncertainties, and market inefficiencies—significantly hinder participation in flexibility markets.

To address these barriers, this research proposes a series of policy and market interventions. These include expanding knowledge and awareness initiatives, improving regulatory frameworks to incentivise flexibility, strengthening the role of system operators, and reforming financial incentives to reduce transaction costs. By aligning policy objectives with market needs, the Dutch electricity system can move towards a more flexible, efficient, and resilient grid, supporting the energy transition while ensuring system stability and economic viability for its users ... Read more

Municipalities carry responsibility for implementing the heating transition, but progress differs even under the same national rules and funding structures. The study examines why collaboration between Buurkracht and four municipalities Boxtel en Sint-Michielsgestel, Leeuwarden, Rotterdam and Zaanstad develops in different ways and how these differences affect neighborhood level work. These municipalities are all part of the BZK12 project with Buurkracht. Buurkracht is an intermediary NGO, who works on facilitating a social heating transition. The focus of this study is the collaboration between these four municipalities and Buurkracht.
The complication is that formal agreements describe roles and tasks, yet daily cooperation depends on informal routines, the municipal context and the ability of organizations to adjust to each other. These dynamics are not visible in policy documents and explain much of the variation seen in practice.
The study uses a qualitative comparative case design. Document analysis and paired interviews provide data on rules in use, working patterns and contextual factors. The interviews formed the bases, interviewing both Buurkracht and the municipality per case. Subsequently followed by a document analysis to check interview findings.
Using these methods, the analysis identifies two important concepts. First, absorptive collaboration capacity, meaning how well municipalities and Buurkracht can take in each other’s working styles and translate them into their routines. Second, institutional fit, meaning how well informal expectations and everyday practices align across organizations. When both are strong, collaboration is stable and contextual factors can be worked on together. When either is weak, coordination problems accumulate and implementation slows.
The study concludes that the heating transition depends less on formal design and more on how quickly partners align informal institutions and adapt their routines to local conditions. This points to a need for support that focuses on collaboration capacity and early alignment rather than only technical or procedural guidance.
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The Netherlands must decarbonize long-haul freight on some of the busiest highway corridors in Europe while keeping logistics reliable and costs under control. The most promising electric road systems (ERS) options for heavy-duty freight in the Netherlands are the overhead catenary system (OCS) or in-road inductive charging (IRIC). This thesis evaluates which dynamic charging technology is preferred for deployment on Dutch highways when judged through a stakeholder-weighted, multi-criteria lens. Decarbonizing heavy-duty road transport demands infrastructure choices that are technically robust, economically viable, environmentally responsible, and socially/institutionally legitimate. Because these choices are inherently multi-actor, the analysis explicitly embeds stakeholder priorities into the technology comparison, moving beyond purely techno-economic ranking toward a decision support tool that reflects how Dutch actors actually weigh trade-offs.
The study adopts a Multi-Actor Multi-Criteria Analysis (MAMCA). First, a literature-based indicator framework defines a common evaluation space across four categories, technical, economic, environmental, and social/institutional, covering criteria such as energy efficiency, technology readiness, grid and power integration, safety, deployment speed & constructability, CAPEX per kilometer, economic feasibility, environmental and visual impacts, social acceptance, and interoperability. Second, semi-structured interviews and a Best-Worst Method (BWM) elicitation capture how five stakeholder groups, the road authority, regulatory authority, energy providers, ERS technology providers, and logistics operators, assign technology-specific weights to those criteria for both OCS and IRIC. These weights are aggregated by stakeholder group and combined with normalized baseline performance scores from the literature to produce stakeholder-specific totals and an overall ranking.
Across stakeholder groups, OCS leads IRIC by +0.04 (Road authority), +0.14 (Regulatory authority), +0.20 (Energy provider), +0.08 (ERS technology providers), and +0.57 (Logistics operator), for an overall advantage of +0.20. Due to the only slight difference this points to broad convergence rather than a decisive winner. Both technologies appear viable under current assumptions, and small shifts in a few high-impact factors could change local preferences. Diving into more detail, OCS demonstrates stronger performance on the criteria deployment speed & constructability, grid & power integration, technology readiness, and CAPEX per kilometer, while IRIC’s key preferences lie in lower visual intrusion and perceived social acceptance. Environmental impacts are broadly comparable under dynamic charging assumptions, with differences driven more by implementation context and energy mix than by the transfer technology itself. Second, stakeholder prioritization is not uniform. Authorities and regulators systematically elevate interoperability, permitting, and cross-border alignment; energy providers emphasize grid-fit and CAPEX; logistics operators prioritize constructability and operational practicality; and technology providers prefer grid integration for OCS and economic feasibility for IRIC. These prioritization patterns matter because they amplify precisely those criteria where OCS tends to lead in the Dutch motorway context. Third, when weights and scores are combined, OCS emerges with a clear, though not absolute, aggregate advantage. Profiles that heavily privilege visual impact and interoperability can narrow the gap, but they rarely overturn the overall ranking given the concurrently high importance placed on grid integration, deployment speed & constructability, and cost.
The policy and implementation advice is concrete. For near-term national rollout on Dutch trunk roads, OCS aligns better with the priorities of the most directly responsible public actors and the operational needs of energy and logistics stakeholders. Sequencing early corridors where grid connection architecture is straightforward, construction interfaces are mature, and costs are minimized will maximize early certainty and learning benefits. At the same time, the analysis identifies the conditions under which IRIC could become competitive at corridor scale. Credible evidence of faster, less disruptive deployment and accelerated standardization for inter-operator interoperability will shift the preferences more to IRIC. Targeted pilots that directly test these leverage points would be the highest-value investments for maintaining optionality.
The thesis also clarifies risks and limitations. Results are conditional on the indicator set, the literature-derived baseline scores, and the observed stakeholder weights at the time of study. While sensitivity checks show the overall preference for OCS to be robust, strong shifts in CAPEX assumptions, grid reinforcement costs, or permitting regimes could materially change the ranking. In addition, social acceptance remains locally contingent. Visual impact is a downside for OCS in sensitive landscapes, and inclusive design, corridor selection, and mitigation measures will be decisive for legitimacy.
Furthermore, the thesis advances Electric Road System evaluation by turning qualitative stakeholder views into a transparent, quantitative decision frame for the Dutch highway context. The result is a stakeholder legible, evidence anchored ranking that clarifies which criteria drive the overall preference and under what conditions the ordering could change, providing usable decision support for ministries, road authorities, grid operators, technology suppliers, and logistics firms.
In sum, when evaluated through a stakeholder-weighted multi-criteria framework tailored to Dutch highways, OCS currently scores 2.50 versus 2.30 for IRIC at the overall level. This makes OCS the more favorable near-term option for Dutch roads. The margin is not structural. It could narrow if IRIC can prove faster deployment, deliver credible interoperability, and achieve cost certainty in Dutch corridor conditions. Targeted IRIC pilots that specifically test those levers keep strategic optionality alive. By making the weight-score trade-offs explicit and actor-legible, this thesis provides decision support for ministries, road authorities, grid operators, technology suppliers, and logistics firms.
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Dutch ports face significant environmental challenges due to high greenhouse gas and air pollutant emissions from berthed ships engaged in essential operations. Entities like the Port of Rotterdam and research institutes produced emission inventories to gain insight into ports' environmental impact. 

However, existing emission inventories rely on fixed factors and overlook berthing duration and activities: they assume the same emission factors regardless of the operations performed by vessels. Thus hindering effective emission reduction strategies and infrastructure development. 

Consequently, the following research studies areas of improvement for the current emission calculation methods by including berthing time patterns. Then, it will apply this information to the Port of Rotterdam to test the new methodology.

The principal result that emerged from this work is that reality is far more complex than the most widely used models to represent it; luckily, the available data can still grasp this complexity. First, not all berthing events are equal, and the rarest ones still hold a considerable impact on the total berthing time. Additionally, the differences do not exist only as a matter of frequency and duration but also imply different energy requirements, as suggested by the interviewed parties. Consequently, a model based on a standard stop only reliably captures part of the behaviour of moored ships. Second, there is no universal relationship between standard industry size classes and time spent in port. Some ship types show a positive linear behaviour (the larger the ship, the longer the visit berthing time), while others show more complex relationships. Moreover, some fleet types belong to only a few classes; therefore, no size-related difference can be observed in the behaviour of berthed vessels. These considerations apply to metrics of volume (GT), maximum transportable weight (DWT), and also cargo capacity (TEU). Consequently, the size classes commonly used in the industry - which reflect the physical limits of channels, ports, and other waterways - might be insufficient to portray the in-port behaviour of all the fleet types. Third, most ships berth at a single location during a port visit, proving that the duration of a port visit could be the only way to identify different types of berthing events. Finally, even the interviews suggested that the system is much more complex than captured by the currently used models. The division by fleet type might be an oversimplification as the product transported and the ship type considerably influence the behaviour in port and energy consumption.

These results contrast with the emission calculation methodologies commonly used in literature and policy documents, indicating a widespread risk of policy and investment failure because partial data and oversimplified models of reality might have driven policy and economic decisions. Thus, institutions may have enacted regulations with potentially inefficient economic, environmental, and social returns. Consequently, improving the system's knowledge is essential for informed decision-making and risk minimization. This research has shown that this objective is not only reachable but could be achievable without exponentially increasing the required data. ... Read more

The Dutch electricity grid is facing significant pressure due to increased intermittent renewable energy generation, advancements in electrification and the rise of major electricity users. Transmission capacity has already reached its limit in several regions in the Netherlands. This leads to network congestion, which delays sustainable development in the energy sector and creates an unnecessary rise of electricity prices. Congestion problems exist in multiple EU countries. ACER has proposed the split of several electricity bidding zones in the EU as a solution to mitigate grid congestion. One of these proposed splits is the separation of the electricity bidding zone of the Netherlands into two bidding zones: a northern and a southern bidding zone. This split will separate the northern provinces of Friesland, Groningen, Drenthe and Overijssel from the other provinces in the Netherlands. Splitting large bidding zones into smaller zones could improve market efficiency by providing more accurate price signals. This will theoretically also lead to less congestion in the long term. While research has been conducted on the proposed split of the bidding zone split in Germany, research about a split in the Netherlands and its effects on the Dutch electricity market is lacking. Therefore, this thesis has investigated the following research question: "How will splitting the electricity bidding zone in the Netherlands impact commercial cross-border exchanges and electricity prices in the Day-Ahead market in the Netherlands and its neighboring countries, and what risks does this split cause for energy companies?

To answer this question, a literature review was performed on the bidding zone split of Germany and Austria in 2018, which shows similarities to the proposed Dutch bidding zone split. Furthermore, a model was created with Plexos optimization software to do a nodal analysis of the Netherlands before the split, as well as a scenario analysis of the Netherlands before and after the split. These analyses used a backcast of September 2022 until December 2022. Lastly, the risks for energy companies due to the split were identified. These are the key findings of the research:

1. The neighboring zones next to Germany and Austria suffered from unscheduled flows from Germany. These unscheduled flows form a problem for the Dutch electricity grid as well. The DE-AT split reduced these unscheduled flows but did not achieve all desired effects concerning congestion resolution because of the remaining internal congestion in the German electricity system. The same may be true for the Netherlands and its proposed split.
2. Austria experienced higher electricity prices post-split. Similar consequences are expected of the Netherlands, where the south of the Netherlands will experience higher electricity prices. The north of the Netherlands, which has a relatively low demand and high renewable capacity, will experience reduced prices.
3. The reduction of market liquidity in Austria after the split was only found in long-term contracts, and can be resolved by adapting the terms of these contracts.
4. Nodal prices in the Netherlands in the evaluated period resulted in a distribution of two price groups: high-priced nodes in the west and low-priced nodes in the east of the Netherlands. This difference in nodal prices can be explained by three reasons: the load density in the west, congestion patterns in the high-priced areas, and the geographical positions of fossil power plants.
5. The scenario analysis, which varied inter-zonal commercial transmission capacity between the new Dutch zones and its neighboring zones, found some interesting results. It was observed that an available transmission capacity of 30\% or below creates a significant price difference between the northern and southern NL zone, while above 50\% prices converged. In the scenarios with low available transmission capacity, the northern NL zones reached prices of 0€/MWh. The scenario that is the closest to the predicted after-split situation has price differences between the northern and southern zones. An experiment was executed to investigate the effect of the split on large electricity users, e.g. a large zinc factory with a capacity of 150 MW. In the investigated 4 months, the factory would pay 1.4M€ more for electricity in the southern zone than in the northern zone.
6. Due to the possible price differences in the NL zones, energy companies face risks. It is advised that the current state of their asset portfolio should be assessed based on the location of contracted or owned electricity supply and the location of consumers. By investing in new generation projects in the southern zone, energy generation companies can potentially increase their profits due to the increased electricity prices in the southern zone after the split.

Further research is needed to provide a more exact calculation of the new commercial transmission capacity between the new NL zones and to include the bidding zone split in Germany to capture the full extent of changes in the Dutch bidding zone split. Lastly, a congestion analysis before and after the split can show policymakers and grid operators if congestion has improved and whether a bidding zone split in the Netherlands is worth it.
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