Nov 11, 2021
Hydrogen (H2) is seen as an important energy vector for decarbonizing the European energy system in the next decade. While there are multiple ways to produce low carbon H2, producing it from renewables is the main pathway being considered in Europe. In its H2 Strategy, the European Commission has set a target to install at least 40 GW electrolyzers and produce up to 10 million mt of renewable H2 production by 2030. This target leaves open a large range of possible outcomes for the overall supply of both renewables and electrolyser capacity needed. The challenge for the next decade is to lay down policy mechanisms that spur efficient business models and scale up low-cost production of renewable hydrogen. The overlap of power and hydrogen systems add some complexities to this challenge, as any regulation needs to ensure the electricity sourced for producing H2 is low carbon and does not cannibalize renewable capacity addition for the power system itself.
Driven in part by the high inefficiencies/losses from electrolysis (~30%), the amount of renewable electricity required for H2 production is enormous. For example, to meet the EU’s hydrogen production target, an additional 160 to 477 TWh/year of renewable electricity supply is required by 2030. To put the scale of the challenge in context, the entire EU27 power system added just over 380 TWh/year of renewables and hydro generation in the decade between 2010 and 2020. Platts Analytics estimates the power system itself will require a renewable generation growth of ~650TWh (excluding demand from electrolysis) from 2021-2030 due to higher electrification and broader decarbonization goals.
The European Commission has strongly emphasized the principle of additionality for H2 production (“additional renewable electricity consumption must always be covered by additional renewable capacity”). The argument for additionality is that any TWh of renewable electricity used for H2 production should not replace electricity that would have otherwise helped decarbonize the power system itself. The principle of additionality would lead to primarily standalone business models for electrolyzer installation with no use of grid power (to avoid redirecting grid power to H2 production). In such conditions, Platts estimates primarily two business models to emerge, based on cost and synergy.
The first model combines electrolyzers with offshore wind. Despite being the highest cost technology on a capital cost basis, offshore wind’s merit for H2 production lies in its high-capacity factor (~45-55%). The higher capacity factor of offshore wind technology would require less electrolyzer capacity to meet the given supply target. Platts’ modelling suggests in regions with high wind potential (such as Northwestern Europe) the cost saving from higher operating hours would more than offset the higher capital costs for offshore wind, making it one of the lowest cost options for standalone H2 production (without grid connection).
The second standalone model combines onshore wind and solar, along with electrolyzers. Combining the two technologies solves the issue of the relatively lower capacity factors of these technologies as solar and onshore wind have complementary running patterns as the former peaks during summer and the day while the latter typically drops during these periods and picks up after the summer period. The key consideration in this model is the relative sizing of the wind, solar and electrolyzer technologies, which will depend on the location.
Given the initial pipeline of projects and the European Commission’s strict stance on additionality, Platts Analytics expects large amounts of the early projects to follow the dedicated renewables and electrolyser business model with limited to no access to grid power. The large proportion of thermal generation in the current power system also hinders the prospect for tapping into the grid for renewable power only, especially without a tested certification system. Such projects would require considerable policy support and innovative arrangements such as PPAs or combined wind and solar sites to maximize the running hour for electrolysers.
Over time, as policy mechanisms such as guarantees of origin are put in place, and renewables make up for a much larger portion of the power system, there could be more opportunities for electrolysers to tap into the grid power (with appropriate certification). Electrolysers could then access grid power during periods of surplus renewables generation and help absorb excess power which might otherwise be curtailed. It remains to be seen whether policy will be conducive to such a system given the principle of additionality would not be followed. If there is indeed a shift to grid connected electrolysers, it would require appropriate certification mechanisms and an abundance of renewables on the system. Given the large benefits to both the power and hydrogen systems, Platts Analytics expects scaling up of grid-connected electrolyser projects with appropriate mechanisms around the middle of this decade.
Besides these standalone models, there are benefits to connecting electrolyzers to the grid. If appropriate regulations such as guarantees of origin are in place – electrolyzers could provide much needed flexibility in the power grid.
During summer, when there are periods of low power demand and surplus renewables generation, electrolyzers could absorb excess generation. The H2 produced from the excess generation could then be used though turbines or fuel cells to produce power during periods when there is typically a large gap between renewables supply and power demand, either intraday or seasonally. The H2 production during the surplus renewables period would not violate the additionality principle since any power produced during this period would otherwise be curtailed. This would improve the economics of renewables by limiting curtailment as well as increasing the overall capture power prices. The higher economic incentive for renewables newbuild could in turn accelerate capacity deployment for power system decarbonization.
Along with electric vehicles and large-scale demand-side response, electrolyzers could act as one of the few sources of flexible power demand in a decarbonized grid. H2 burning turbines and fuel cells remain one of the few low carbon dispatchable power generation options besides gas and coal CCUS, biomass and nuclear plants. While batteries can provide flexible generation for up to 4-8 hours at a stretch, a high renewable system could see many weeks of low wind and solar output which will need to be backed by firm low carbon generation. H2 turbines or fuel cells could therefore play a very important from a security of supply standpoint during extended periods of supply crunch.
H2 turbines have a similar configuration as their gas-fired counterparts, apart from the requirement to install components for additional NO2 emission capture (which increases the CAPEX by ~9-10%). The main cost differential with gas turbines will be on variable cost as H2 is currently significantly more expensive than natural gas, even considering Europe’s carbon trading scheme. The key challenge over the next decade and more is to bring H2 costs down by scaling the technology through effective market mechanisms. Many support mechanisms are being proposed across Europe to allow initial deployment, ranging from fuel price support to close the cost differential with natural gas to capacity support mechanisms like the existing capacity markets.
For more data and analysis on green hydrogen, including a country- level supply and demand forecast, please check out the recently release report “European Hydrogen Long-term Forecast” https://secure.pira.com/markets/Future-Energy-Outlooks/?pdf=euhydrogen102921.pdf