How is hydrogen produced, and does the colour matter?

An electrolyser splits water (H2O) into hydrogen and oxygen using an electric current. The two main commercial technologies are proton exchange membrane (PEM) electrolysers, which respond quickly to variable power input and suit renewable coupling, and alkaline electrolysers, which are cheaper and more mature but slower to ramp. A 10 MW electrolyser produces roughly 4.3 tonnes of hydrogen per day. The energy conversion efficiency is typically 55-70 per cent, meaning roughly a third of the electrical energy input is lost as heat. This is why cost of electricity dominates green hydrogen economics.

Blue hydrogen depends on natural gas as a feedstock, which means methane leakage during extraction, processing, and transport must be accounted for. Methane has a global warming potential roughly 80 times that of CO2 over a 20-year horizon. Studies by Howarth and Jacobson (2021) argued that lifecycle emissions from blue hydrogen could be worse than burning natural gas directly if upstream methane leakage exceeds 3 per cent. The UK Low Carbon Hydrogen Standard addresses this by requiring full lifecycle accounting, but measurement of upstream emissions remains contested and varies significantly between gas supply chains.

The CCUS Cluster Sequencing Process is how DESNZ decides which industrial clusters receive government support first. Track 1 clusters (HyNet and East Coast) receive priority access to the Transport and Storage Regulatory Investment (TRI) model, the Hydrogen Production Business Model, and the Industrial Carbon Capture business model. Track 2 clusters must wait until Track 1 projects demonstrate viability, creating a delivery gap that affects the Scottish and South Wales clusters. This sequencing decision effectively determines which regions get hydrogen infrastructure first, and which projects can attract private investment.

Hydrogen Allocation Rounds (HAR) are the competitive process through which projects bid for Hydrogen Production Business Model contracts. HAR1 (December 2023) was open to both electrolytic and CCUS-enabled projects, with 11 projects shortlisted. HAR2 (2024) focused on electrolytic hydrogen and shortlisted a further tranche of projects. The process requires projects to demonstrate technical readiness, planning consent, grid connection, and a credible offtake strategy. The gap between shortlisting and financial close has been the main bottleneck, with negotiation of detailed contract terms taking longer than the government initially anticipated.

The gas distribution networks have been replacing old iron gas mains with polyethylene pipes since 2002 under the Iron Mains Replacement Programme (IMRP). Polyethylene pipes are hydrogen-compatible. By 2030, roughly 90 per cent of the distribution network below 7 bar will have been replaced, meaning the local distribution grid could technically carry hydrogen without major further investment. However, this does not address the transmission system, metering, appliances, or the significant cost of converting every connected property.

The Hydrogen Village Trial was planned for Redcar in the north-east of England. It would have converted approximately 2,000 homes to hydrogen heating, providing real-world evidence on consumer acceptance, safety, network performance, and cost. The trial was cancelled in December 2023 after Northern Gas Networks withdrew following local opposition and rising cost estimates. Without this evidence, the government lacks a domestic-scale test case for hydrogen heating, making the strategic decision harder to justify on evidence grounds.