The European Commission (EC) has set ambitious targets of achieving 60 GW and 300 GW of offshore wind capacity by 2030 and 2050, respectively, to meet its energy and climate objectives. This push towards renewable energy necessitates the integration of hybrid offshore wind farms (OWFs) connected to multiple countries and markets, facilitating cross-border electricity connections, security of supply, and increased renewable energy integration. Hybrid projects, combining OWFs and interconnector transmission cables, play a crucial role in this transition, aiming to create a meshed offshore energy network in the North Sea.

The development of the European Target Model, incorporating Flow-Based Market Coupling (FBMC), Advanced Hybrid Coupling (AHC), and the Offshore Bidding Zone (OBZ), aims to address challenges in hybrid projects but introduces new price and volume risks. These risks, stemming from the unique market mechanisms of the OBZ and the increased dependency on interconnectors, lead to revenue uncertainties and potential curtailment for offshore wind farms (OWFs), complicating investment climates and hindering the achievement of renewable energy targets.

The main objective of this thesis is to identify the key factors leading to price and volume risks for hybrid projects and assess the effectiveness of mitigation measures. This is achieved by answering the main research question in this thesis: How do the offshore grid topology, onshore grid attenuations and the integration of renewable energy
sources influence price and volume risk and to what extend do regulatory and technological measures
mitigate these risks?
Aiding in answering this question, four subquestions have been introduced, aimed at identifying specific price and volume risks, exploring regulatory and technological mitigation measures, determining the most impactful risk factors on OWFs' economic viability, and evaluating the potential mitigation measures' effectiveness.

The research approach consists of two phases: qualitative desk research and quantitative modelling. The first phase involves a literature review to identify and categorize price and volume risks and mitigation measures, forming a risk framework. The second phase addresses the Risk Framework from phase 1 and uses it to extend the model from Kenis et al. (2023) to quantify the frequency and severity of the risks and ultimately determine the key factors leading to these risks. The primary research method applied in this thesis is a linear optimisation model mimicking the FBMC process of TSOs deployed in Julia. The methodology encompasses a four-key steps process. In the first step, the Case Determination, indicators are established to define case groups and systematically vary variables and isolate the primary considered variables, i.e. offshore grid topology, onshore grid attenuations, and renewable energy integration. In the second step, the Case Simulation, the base case (D-2), day-ahead market clearing (D-1) and redispatch (D-0) modelling steps of the FBMC process are simulated, followed by the added modelling step to distinguish between the capacity calculation and allocation volume risk and the calculation of the risk indicators. In the third step, the Case Group Analysis, case-specific results are collected and analysed per case group and an ex-post analysis of the FTR and TAG compensations is conducted. Th final step, the Cross-Case Group Analysis, involves aggregating and analysing all results with the aid of standardisation methods to create Risk Matrices.

The study identifies two key factors leading to price and volume risks: the transmission grid’s physical characteristic, i.e. the OBZ’s export capacity or FB domain as influenced by the offshore grid topology and onshore outages, and the market characterises of the bidding zones connected via the hybrid interconnector, i.e. the level of competition between the OBZ and onshore (renewable) generators for the allocation of scarce transmission capacity.
Changes in offshore grid topology primarily impact price and volume risks by altering the OBZ's export capacity, with increased transmission capacity generally reducing curtailment by capacity calculation but potentially affecting price collapses and curtailment by capacity allocation depending on onshore grid restrictions and market dynamics. Onshore grid attenuations similarly influence these risks, with high-priced zone outages typically increasing curtailment by capacity allocation and price collapses,
while low-priced zone outages increase curtailment by capacity calculation and positive non-intuitive price formation. The integration of renewable energy sources in onshore markets exacerbates competition for transmission capacity, leading to more frequent curtailment by capacity allocation and price collapses during high-wind hours.
Technological mitigation measures, i.e. flexible demand agents (e.g. offshore and onshore electrolysers), mitigate price and volume risks by increasing local demand in the OBZ, setting a floor price and raising electricity prices, and decreasing the need for wind exports, which reduces curtailment by the capacity allocation and calculation risks. FTRs effectively cover price spreads, prevent price collapses and non intuitive price formation. The TAG moderately compensates for curtailment by the capacity calculation volume risk.

Policy makers should actively promote the deployment of flexible demand technologies to balance supply-demand mismatches and support renewable energy generation. They should also decide on a support strategy for hybrid projects, either a merchant-based approach focusing on flexible demand deployment or a regulatory approach implementing FTRs and TAG, potentially including 2-sided capability-based CfDs for initial projects to address supply/demand mismatches. TSOs should strategically select inland landing points and prioritize grid enhancements to mitigate structural congestion and reduce hybrid projects' exposure to price and volume risks, while timely communicating potential delays in intra-zonal and cross-border transmission developments to developers. Developers should pro-actively invest in flexible demand assets to mitigate price and volume risk and increase OWF revenues, optionally focussing on strategic locations of onshore assets near landing points. Finally, uniform decision-making and alignment in hybrid project design and support instrument deployment across North Sea countries are crucial, potentially facilitated by establishing an independent Offshore Transmission System Operator and an Offshore Investment Bank to manage transmission assets and reallocate costs and benefits among stakeholders.