Cost and competitiveness of green hydrogen and the effects of the European Union regulatory framework

The European Commission (EC) published the first regulatory framework for classifying renewable hydrogen (green hydrogen) via delegated acts supplementing the revised Renewable Energy Directive. Industry stakeholders argue the rules are overly strict and will raise production costs, potentially undermining EU competitiveness and a rapid production ramp-up aligned with REPowerEU goals. Conversely, NGOs consider the rules too lenient, warning of possible increases in greenhouse gas (GHG) emissions if fossil-based grid electricity powers electrolysers, which could counteract power sector decarbonization. This paper quantifies the effects of the delegated acts on green hydrogen production cost, renewable characteristics, and electrolyser plant design and operation in the EU. Green hydrogen is central to the EU’s target to cut GHG emissions by at least 55% by 2030, and a rapid scale-up of fossil-free domestic hydrogen is viewed as crucial for decarbonization and reducing gas import dependency. Although the delegated acts currently apply to green hydrogen in the mobility sector, the rules are likely to serve as a benchmark for future sectoral regulations.

Prior work has examined factors affecting hydrogen production costs and electrolyser plant design. Notably, one study uses linear optimization to assess how varying electricity prices and uncertainties in PV and wind supply influence hydrogen cost. Another evaluates how combining grid electricity purchases with on-site renewable generation affects production cost. Additionally, an electricity market modeling study indicates how potential green hydrogen classification regulations could impact total welfare, carbon emissions, and hydrogen supply cost in Germany. These studies provide methodological and contextual foundations for assessing regulatory impacts on green hydrogen economics and sustainability.

The study develops a linear optimization model to co-optimize design and operation of a green hydrogen production system comprising a PEM electrolyser (stack and peripherals), an electric-motor-driven piston compressor, and hydrogen storage, supplied by onshore wind, utility-scale PV, and optionally grid electricity. The objective minimizes total annual cost as the sum of annualized CAPEX and OPEX across components plus grid electricity purchase costs, over a one-year horizon with hourly resolution. The electrolyser stack’s specific energy consumption curve is linearized via a convex stepwise approximation to maintain linearity while capturing improved efficiency below nominal load. Equality and inequality constraints enforce power balances, component operations, capacity limits, storage dynamics, and the linearized stack characteristics. Four evaluation indices are defined: (1) on-site hydrogen supply cost (OHSC), computed as total annualized costs divided by annual hydrogen demand; (2) emission intensity (EI) of hydrogen production, accounting only for purchased grid electricity emissions per delegated act methodology; (3) additionality index (i_add), the ratio of total installed RES capacity (wind + PV) to installed electrolyser capacity; and (4) temporal correlation index (i_corr), measuring simultaneity of RES generation and electrolyser operation weighted by RES share. Power purchase scenarios are derived from the delegated acts. Permissible scenarios include: Direct Connection (DC) with additionality (RES commissioned within 36 months of electrolyser), DC + Renewable Grid (in zones with ≥90% annual renewable electricity), DC + Renewable Redispatch (consumption coincident with downward RES redispatch), and DC + PPA (renewable power purchase agreements with additionality, hourly temporal correlation, and geographic correlation). An impermissible scenario (DC + PPA + Grid) allows unrestricted grid mix purchases alongside PPAs. For analysis, DC + Renewable Grid is excluded (few EU zones ≥90% RES) and DC + Renewable Redispatch is excluded (ancillary services not broadly regulated). Assuming zero grid fees/taxes and strict additionality (all RES are new), local RES purchase is economically similar to PPAs; thus the permissible DC and DC + PPA are merged into the Renewable scenario, and the impermissible DC + PPA + Grid becomes the Mix scenario. Transitional softening scenarios are also assessed: Balance (monthly RES generation must at least equal electrolyser monthly consumption for PPA-sourced electricity, allowing grid usage); and RES Share (annual RES share in electrolyser consumption ≥90%, allowing grid usage), akin to DC + Renewable Grid in spirit. A variance-based variable importance analysis identifies key uncertain inputs: availability of renewables (AoR, using capacity factor time series for PV and wind across 20 European locations), grid electricity price (GEP), and average grid EI. The model parameters and costs reflect present-day values (2023 euros). Geographical correlation is assumed satisfied; life-cycle emissions of RES and equipment are set to zero following DA methodology. Optimization is implemented in Matlab with Gurobi; uncertainty analysis uses UQLab.

- Allowing unrestricted grid mix use (impermissible under current rules) does not necessarily increase GHG emissions relative to grey hydrogen and can reduce production costs. Economic incentives at current price levels drive substantial integration of low-LCOE PV and wind, lowering EI in many EU locations. - Cost impacts: In a medium-availability location, the Mix scenario achieves OHSC advantages over the Renewable scenario ranging from 5.93 €2023 per kg H2 at low GEP to 0.23 €2023 per kg H2 at high GEP; at the average EU non-household GEP (H1 2023), the advantage is about 1 €2023 per kg H2. Across 20 EU locations (AoR variation) at average EU GEP, OHSC advantages mostly fall between 0.55 and 1.62 €2023 per kg H2. - Emissions: In the Mix scenario, EI decreases steeply once GEP > 0.05 €2023 kWh−1 due to RES integration. At average EU GEP, EI reduction vs grey hydrogen ranges from ~95% (using France’s grid EI) to ~75% (using Greece’s grid EI). However, for GEP < 0.12 €2023 kWh−1, high grid mix usage can lead to EI up to 2.73× that of grey hydrogen. - Additionality and operation: The Mix scenario’s additionality index rises with GEP; at average EU GEP it reaches ~95% of the Renewable scenario and exceeds it above 0.3 €2023 kWh−1, enabled by flexible procurement that favors more PV without as much reduction in wind compared to the Renewable case. For GEPs above the EU average, temporal correlation exceeds 90% and electrolyser sizing/utilization converge between Mix and Renewable. At lower GEPs, Mix favors a smaller, more intensively used electrolyser. - Transitional softening scenarios: Both Balance (monthly RES ≥ consumption) and RES Share (annual RES share ≥90%) yield OHSC advantages similar to the impermissible Mix scenario for GEPs above the EU average. RES Share shows slightly higher OHSC benefits than Balance, ranging from 1.89 €2023 per kg H2 at low GEP to 0.23 €2023 per kg H2 at high GEP in the medium AoR case. For GEPs above the EU average, EIs in both transitional scenarios are comparable to Mix and deliver substantial savings versus grey hydrogen (conclusion cites ~85% emissions savings at EU-average conditions). At lower GEPs, Balance requires more wind capacity (less seasonal variability but higher cost), which increases additionality and electrolyser utilization but leads to higher EI than RES Share; RES Share leverages cheaper PV for slightly greater cost reductions and an electrolyser design more aligned with the post-transition Renewable scenario. - Overall: Under current EU electricity price levels, economic drivers alone tend to ensure EI below that of grey hydrogen in most locations while delivering notable cost reductions, though low GEPs can reverse this by incentivizing grid mix use.

The study addresses the policy controversy by quantifying how EU delegated acts on green hydrogen procurement influence costs and emissions. It shows that prohibiting grid mix use is not strictly necessary to avoid higher emissions when electricity prices are at current levels, since economic optimization favors integrating new RES capacity. Thus, the EC’s and NGOs’ concerns about inevitable EI increases are only conditionally valid—risks arise primarily at low electricity prices and low renewable availability. Industry concerns about cost increases under strict rules are partly supported; however, the transitional softening provisions (monthly balance or annual RES share thresholds for PPA power) deliver cost advantages comparable to an unregulated (impermissible) mix while maintaining high renewable usage and significant emissions reductions, mitigating both cost and environmental concerns during the ramp-up phase. Design implications emerge: Balance promotes wind-heavy builds with higher additionality and high electrolyser use, while RES Share leans toward PV, enabling lower costs and an electrolyser size more suitable for post-transition conditions. Overall, the results suggest a nuanced regulatory approach can preserve environmental integrity and competitiveness, with economic incentives playing a central role in driving RES integration.

Unrestricted grid electricity usage for green hydrogen does not inherently increase production-related emissions and can reduce costs by roughly 0.55–1.62 €2023 per kg H2 across many EU locations. Yet, at low electricity prices, such unregulated use can drive EI up to 2.73 times that of grey hydrogen, underscoring the rationale for regulation. Transitional softening of temporal correlation requirements for PPA-sourced electricity ensures high renewable usage and substantial emissions savings while delivering cost benefits similar to unregulated procurement. Under current price levels and medium renewable availability, a cost advantage of about 1 €2023 per kg H2 and emissions savings around 85% relative to grey hydrogen are achievable. Adjusting the softening (e.g., adopting annual RES share thresholds) could further enhance cost and emissions outcomes and produce designs better suited to both transition and post-transition operation, offering a constructive pathway for upcoming sectoral regulations. The findings, contingent on the study’s assumptions, aim to inform balanced policy that supports both environmental objectives and the economic viability of green hydrogen in Europe.

Results are conditional on key assumptions: the perspective is a single electrolyser plant (system-wide grid effects are not modeled); evaluation of emissions follows the delegated acts’ methodology and excludes full life-cycle emissions (construction, decommissioning, and RES generation life-cycle impacts are assumed zero), despite literature showing nonzero life-cycle GHG for PV, wind, and electrolyser systems. Temporal variation in grid emission intensity is not modeled (an annual average is used due to data limitations). Geographical correlation impacts on grid infrastructure are assumed satisfied and not analyzed. Electricity taxes and grid fees are set to zero to avoid country-specific effects. Offshore wind supply and prospective future cost trajectories are not included. Given these constraints and the inherent uncertainties, the study cannot fully resolve the policy controversy but provides insight into the economic and sustainability implications of the current EU framework and transitional provisions.