The European Union aims to drastically reduce greenhouse gas (GHG) emissions, with green hydrogen playing a pivotal role. The European Commission (EC) introduced delegated acts (DAs) to classify renewable hydrogen, supplementing the revised Renewable Energy Directive (RED II). These regulations, while initially focused on the mobility sector, are likely to set precedents for other sectors. However, the DAs sparked immediate controversy. Industry players criticized the stringent rules, predicting higher production costs and hindering the expansion of European green hydrogen production, conflicting with the goals of the REPowerEU plan. Conversely, NGOs viewed the regulations as too lenient, potentially leading to increased GHG emissions due to permitted fossil fuel electricity use in hydrogen production, thus undermining efforts towards power sector decarbonization. This research addresses this controversy by quantitatively assessing the impact of the DAs on green hydrogen production costs, renewable characteristics, and the design and operation of electrolyzer plants within the European Union. The study's objective is to provide a data-driven evaluation of the opposing viewpoints, using a rigorous mathematical model to analyze various power purchase scenarios under realistic conditions.

Existing literature extensively examines factors influencing hydrogen production costs and electrolyzer plant design. Several studies utilize linear optimization to assess the impact of variable electricity prices and renewable energy supply uncertainty on hydrogen production costs. Other research explores the cost implications of combining grid electricity with on-site renewable energy sources. One study, in particular, employs an electricity market model to predict the consequences of potential green hydrogen classification regulations on welfare, emissions, and supply costs within Germany. This paper builds upon this existing body of knowledge by incorporating the specific regulatory framework defined by the EC's DAs and examining its consequences under diverse European conditions, going beyond previous localized analyses.

To quantify green hydrogen production costs and renewable characteristics, the researchers developed a linear optimization model. This model minimizes the total annual cost of a hydrogen production system, encompassing capital expenditure (CAPEX) and operational expenditure (OPEX) for all system components. The model incorporates various power purchase scenarios derived from the DAs. These scenarios include direct connection (DC) to renewable energy sources (RES), scenarios where additional grid electricity is used under specified conditions (e.g., high renewable electricity share in the bidding zone, participation in imbalance settlement), and scenarios using power purchase agreements (PPAs) with RES providers. An "impermissible" scenario is also included, allowing for the purchase of unrestricted grid electricity mix, which is prohibited by the DAs. The model accounts for a range of uncertain input parameters, such as electricity prices and renewable energy availability across different European locations. To improve the precision and efficiency of the model, the researchers employ a stepwise linearization technique to represent the non-linear characteristics of the electrolyzer stack. Four evaluation indices are used to compare the scenarios: on-site hydrogen supply cost (OHSC), equivalent carbon dioxide emission intensity (EI), additionality index (reflecting the extent of new RES installations), and temporal correlation index (measuring the simultaneity of RES generation and hydrogen production). A variable importance analysis (VIA) is conducted to identify the most influential uncertain input parameters affecting the evaluation indices. The model was implemented in MATLAB, using Gurobi as the solver. The study uses current cost values derived from recent publications and converted to euros (2023 values) using the Chemical Engineering Plant Cost Index (CEPCI). The model considers a yearly timeframe with hourly resolution. The results were analyzed to determine the influence of the EC's regulations on cost competitiveness and environmental impact, specifically comparing the permissible scenarios with the impermissible scenario and two scenarios incorporating transitional rules allowing for more flexible grid electricity integration. The analysis accounts for variations in grid electricity prices, renewable energy availability across different European locations, and the emission intensities of the grid electricity mix in those locations.

The variable importance analysis revealed that the availability of renewables, grid electricity prices, and the emission intensity of grid electricity are the most significant factors influencing the results. The study found that the unrestricted use of grid electricity (impermissible under the DAs) does not automatically lead to increased GHG emissions compared to grey hydrogen, particularly at current electricity prices. In fact, this approach could reduce the OHSC by 0.55-1.62 €2023 per kilogram of H2 in many European locations. This finding supports industry concerns about the potentially high cost increases due to the DAs' strict regulations. However, with very low grid electricity prices and low renewable energy availability, using unrestricted grid electricity could substantially increase GHG emissions (up to 2.73 times higher than grey hydrogen), supporting NGOs' concerns. The analysis of transitional rules, which temporarily relax the temporal correlation requirement between RES generation and hydrogen production, showed similar cost advantages as unrestricted grid electricity use. This advantage is caused by using power purchase agreements (PPAs) with RES providers. The transitional rules also maintain relatively high renewable electricity use and significant GHG emission reductions (around 85% compared to grey hydrogen), thus mitigating both industry and NGO concerns. The study identifies two transitional rule scenarios. The "Balance" scenario requires a monthly balance between RES generation and electrolyzer consumption. The "RES Share" scenario mandates a minimum annual share of RES electricity in electrolyzer consumption (90%). The findings indicate that the Balance scenario shows advantages regarding a sustainable RES design while the RES Share scenario better fits for an economically optimized operation when the transitional rules are no longer in effect. Overall, the findings partially invalidate concerns from both industry players and NGOs regarding the impact of the regulations.

The study's results highlight the complex interplay between cost, emission reduction targets, and regulatory frameworks. The findings suggest a nuanced perspective on the controversy surrounding the EC's DAs. While the strict regulations aiming to ensure the green credentials of hydrogen are understandable, the potential cost increase and the possibility for significant cost reductions when allowing for a more flexible grid electricity integration under certain conditions warrant further consideration. The observed economically incentivized increase in renewable energy use when allowing for the purchase of grid electricity even under the strict regulations of the DAs points towards an effective regulatory approach that simultaneously promotes cost efficiency and sustainability. The analysis of transitional rules shows promising pathways to balance the short-term need for a rapid ramp-up of green hydrogen production with long-term sustainability goals. The study underscores the importance of continuous monitoring of electricity prices and renewable energy availability in different European locations to ensure effective policy making. Future research should explore more detailed scenarios incorporating full life-cycle emissions, the use of offshore wind turbines, and forecasting electricity prices to further refine the cost-emission tradeoff in green hydrogen production.

This paper provides a quantitative analysis of the impact of the EC's delegated acts on green hydrogen production. The findings demonstrate that unrestricted grid electricity use doesn't automatically equate to increased emissions, potentially offering significant cost advantages. Furthermore, the transitional rules offer a viable path to balance cost-effectiveness with environmental sustainability. However, the study highlights the risk of high emissions with low electricity prices and low renewable energy availability. Future research should focus on refining the model and evaluating alternative softening strategies that could lead to higher cost and emission reductions while ensuring an economically efficient electrolyzer design beyond the transitional phase.

This study focuses on the design and operation of individual electrolyzer plants and doesn't account for broader system-level impacts or full life-cycle emissions (beyond the calculation methodology used by the EC). The use of a simplified representation of the electrolyzer stack may also influence the results. The model uses current cost data and average grid electricity emission intensities and does not dynamically model their evolution over time. Finally, the analysis assumes the fulfillment of geographical correlation conditions, which might not be uniformly applicable throughout Europe.