In an energy system that meets the UK government’s goal of decarbonising the country’s electricity supply by 2035, hydrogen will probably be needed for back-up power, with a limited role in heating buildings, and blue H2 will be required to meet the majority of demand, according to the UK’s independent climate advisory body.

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In its new report, Delivering a reliable decarbonised power system, released today, the Climate Change Committee (CCC) sets out how the British electricity grid can reach net-zero emissions by 2035, with 42 of its 131 pages dedicated to hydrogen production, use and infrastructure.

“Hydrogen has a crucial role to play in decarbonisation of the energy system,” the study says. “It will be needed for hard-to-decarbonise sectors such as industry and shipping and is expected to have a role in power generation, although the scale of this remains uncertain.”

It adds that hydrogen “is likely” to provide flexibility in the power sector “to store excess power and generate on-demand to back up variable renewables”.

However, green hydrogen produced from renewable energy should take something of a back seat to blue H2 derived from natural gas with carbon capture and storage (CCS), it suggests.

“It appears implausible that all UK hydrogen demand could be met from domestic non-fossil production by 2035, given likely limits on the rate at which renewable generation capacity can feasibly be built.

“Zero-carbon electricity must be prioritised for displacing unabated fossil generation and meeting increasing demands from electric vehicles and heat pumps.”

Later in the study, in a paragraph about reducing fossil-gas imports, it adds that “using hydrogen in place of efficient electrification (eg, instead of heat pumps for buildings) would be a much less efficient use of domestic energy resources, leading to greater need for imported energy to supplement them”.

A second report released by the CCC today, entitled Net Zero Power and Hydrogen Capacity Requirements for Flexibility, written by engineering consultant Afry, states that “blue hydrogen is expected to remain the dominant source of hydrogen production until 2035 [in the CCC’s central scenario]”.

Yet it adds that blue H2 made using autothermal reforming (ATR), the method of extracting hydrogen from fossil gas with the highest carbon capture rates, will be more expensive than green H2 made via electrolysis from surplus renewable power.

“This is despite the fact that the levelized cost of hydrogen (LCOH) for ATR CCS is higher at £50/MWh [$59.50] (real 2020), compared to the cost of electrolysis operating at zero electricity cost (including additional storage costs), which is £34/MWh (real 2020).

“This is due to the limited availability of excess renewable generation for electrolysis once all other balancing methods, such as exporting via interconnectors or load shifting with DSR [demand-side response]/grid storage, are considered.”

It does add, however, that green hydrogen will become dominant over blue in the years between 2035 and 2050 due to “a faster increase in renewable and nuclear generation as compared to electricity demand”.

The main report explains: “It is unlikely that any contributions from green hydrogen imports, or electricity imports for domestic green hydrogen, would remove the need for blue hydrogen on a 2035 timescale.

“The build rates required for the Government’s existing ambitions for zero-carbon electricity mean that further zero-carbon capacity for dedicated hydrogen production is not expected to be available at significant scale by 2035.”


The CCC adds that green hydrogen produced from surplus electricity — at points in time when available power exceeds demand — will be cheaper than if produced via renewables projects solely dedicated to H2 production.

“While electrolysers could be connected to a variety of zero-carbon electricity sources, offshore wind would be the most likely due to its high load factor and low levelised cost of energy,” the report says.

“Green hydrogen produced from a dedicated source of offshore wind has been estimated to cost around £80/MWh in 2035 falling to around £70/MWh in 2050. In contrast, hydrogen produced from curtailed electricity is estimated to cost £46-53/MWh in 2035 and £42-50/MWh in 2050.”

The second report states: “An effective approach to cost-effectively meeting the variable hydrogen demand is to store low-cost green hydrogen produced during periods of surplus renewable energy.”

Due to the priority of decarbonising the power grid, green hydrogen produced from dedicated renewables projects should “only be based on extra zero-carbon electricity capacity or from zero-carbon electricity sources where it is not possible to connect to the grid”, the main study says.

And “existing zero-carbon electricity capacities and commitments must not be allocated to dedicated hydrogen production”.

However, it states that: “Dedicated electrolytic production in the UK is likely to be preferable to importing electrolytic hydrogen. This is due to the uncertainties surrounding the development of an internationally traded market for hydrogen, as well as the lower costs and energy security benefits of domestic production compared to imports.”

Back-up power

The main report says that “the production, storage and use of low-carbon hydrogen plays an essential role in achieving the 2035 goal of a reliable, resilient decarbonised power system”.

“While the precise balance between use of hydrogen-fired turbines and fossil gas plants with CCS in the power sector remains uncertain, some use of some hydrogen to provide on-demand power to meet peaks and back-up renewables appears necessary.

“This is likely to lead to a very variable demand for hydrogen in the power sector, necessitating the use of hydrogen storage to ensure that the necessary hydrogen is available.”

The CCC adds that it has “not attempted to define the appropriate balance of hydrogen and gas CCS for low-carbon back-up capacity, but a mix of the two is likely to be sensible”.

“At least until the 2040s, additional hydrogen demand at the margin might need to be met through blue hydrogen production. As such, the choice might well be between providing low-carbon dispatchable capacity through hydrogen-fired capacity fuelled by blue hydrogen versus gas CCS plants.

“Gas CCS plants have higher capital costs than hydrogen-fired plants, but are expected to have lower operating costs (given a slight advantage in efficiency in going from fossil gas to electricity compared to use of blue hydrogen in hydrogen-fired plants). At higher load factors, the lower operating costs of gas CCS might be sufficient to justify the higher upfront investment, while hydrogen looks preferable at low load factors.”

The report adds that a hydrogen-only approach to back-up power seems “infeasible”, given the planned build rates for H2 production.

“Strategic decisions around infrastructure build which determine the deliverable balance of hydrogen and gas CCS are required urgently.”