The recently revealed British Energy Security Strategy and Net Zero Strategy outline the primary energy plan objectives and hydrogen aspirations of the British government.
Initiatives such as the Net Zero Hydrogen Fund and the Hydrogen Business Model aim to stimulate supply and support the United Kingdom’s goal of achieving 10GW of low-carbon hydrogen by 2030. This article examines recent policy, financial support mechanisms, and the cost of low-carbon hydrogen generation in the United Kingdom.
10GW low-carbon hydrogen by 2030
The British Energy Security Strategy, released in April 2022, calls for a doubling of the United Kingdom’s 2030 hydrogen production goals from 5GW to 10GW. The remaining 5GW is expected to be met by blue hydrogen (natural gas with carbon capture and storage) facilities like BP’s 1GW H2Teesside.
As of April 2022, the UK’s hydrogen project pipeline comprised 20 GW, including nine CCUS-enabled and 39 electrolytic projects. Government subsidies and financial support mechanisms will play a significant role in bringing these initiatives from the development stage to production. The £240 million Net Zero Hydrogen Fund (NZHF) will provide grant financing to cover the up-front expenditures of developing and constructing low-carbon production plants, whereas the Hydrogen Business Model (HBM) will provide a revenue support mechanism.
The Net Zero Hydrogen Fund
Strand 1 provides support for development expenditures for FEED and post-FEED studies (up to 50 percent of eligible expenses); Strand 2 provides support for capital expenditures (up to 30 percent of eligible costs) for projects that do not require revenue support through the HBM. The NZHF’s strands 3 and 4 will assist capital expenditures for projects that also require HBM income support but are not yet accepting applications. The strategy will be divided between projects with and without CCUS capability.
The Hydrogen Business Model
While the hydrogen industry develops, the HBM revenue support model is designed to bridge the cost gap between low-carbon hydrogen and less expensive alternative fuels. Similar to the contract for difference (CfD) model for renewable power projects in the United Kingdom, the proposed terms of the HBM allow the producer to earn a guaranteed return on the costs of creating hydrogen.
The mechanism is organized such that the producer is compensated for each unit of hydrogen produced in proportion to the difference between I the price the producer requires to cover its costs and a permitted return on investment (the strike price) and (ii) the actual realized sales price (the reference price). To prevent the producer from gaining additional subsidy for low-priced sales, a price floor would be imposed at the lesser of the achieved sales price and the natural gas price.
The indicative HBM terms also incorporate a volume risk management mechanism, basically providing the producer with an additional subsidy per unit of hydrogen sold if its offtake/sales volumes were to decline.
The HBM model provides producers with revenue certainty, hence facilitating their access to potentially low-cost funding sources, such as loan markets. In 2023, the HBM will make available £100 million for up to 250MW of electrolytic projects.
The Standard for Low Carbon Hydrogen
At the point of production, the UK’s Low Carbon Hydrogen Standard defines what constitutes “low carbon hydrogen.” The purpose of the standard is to ensure that newly sponsored hydrogen generation contributes to greenhouse gas (GHG) reduction goals. Low carbon hydrogen is defined as produced hydrogen with a GHG emissions intensity of 20gCO2e/ MJ (LHV), including emissions from production, associated CCS activities, compression, and purification. Producers must demonstrate compliance with this criteria. I scope one emissions from off-grid power (considered zero if off-grid, on-site renewable electricity is used); (ii) emissions of the low carbon electricity source in real time if grid linked; and/or (iii) actual national grid average GHG intensity per 30-minute settlement period.
Repercussions for manufacturers
Electrolyser projects are projected to get greater income assistance per unit of capacity from proposed government funding mechanisms than blue hydrogen projects, reflecting the current higher levelized cost of green hydrogen (and hence higher strike price under the HBM). Subsidy levels will vary based on scale, source/cost of electricity supply, technology solution, location, offtake arrangements, and project duration.
With specific reference to the HBM, project developers seeking funding will need to handle technology, volume, and price risks. For instance, volatility in month-ahead natural gas prices in the United Kingdom will need to be considered when evaluating the price floor and designing offtake arrangements to minimize price risk. This would apply to both blue hydrogen projects and dedicated renewable electrolytic operations that do not require natural gas as a feedstock.
British hydrogen production expenses
According to our analysis, the primary determinants of the electrolysis levelized cost of hydrogen (LCOH) in the UK are the input power price and the load factor. The major drivers for steam methane reformation (SMR) with CCUS are natural gas pricing, carbon prices, and carbon storage and transport. On the basis of current capital costs and present futures pricing for wholesale power, NBP gas, and carbon, we estimate that blue hydrogen at $4.50/kg is now around 50 percent less expensive to manufacture than green hydrogen (grid-connected) in the United Kingdom. However, if electrolyser costs and the levelized cost of electricity (LCOE) from offshore wind fall from current predictions of £57/MWh to £20/MWh to £30/MWh, green hydrogen may become cost competitive.
Significant investments in the scalability of electrolyser technologies will be necessary for green hydrogen (usually at the 25-50MW scale) to be competitive with worldscale SMRs (up to 3,000MW). Recent geopolitical events have prompted EU host governments to increase investment for green hydrogen technologies in light of unpredictable gas supply. There is also a growing awareness of the possible balancing benefits of adding rapid reaction electrolysers to a grid dominated by renewable energy sources.
Consequences for disagreements
With a growing number of projects moving from the conceptual phase to commercial demonstration and ultimately full-scale development, as well as substantial private and government investment, we anticipate disputes regarding I evolving technologies, (ii) licensing and regulation, and (iii) supply / offtake agreements.
Alkaline electrolysers and solid oxide fuel cells are mature technologies that have been deployed effectively for decades. However, as businesses seek to lower manufacturing costs, enhance efficiency/flexibility, and lengthen operational lives, innovative solutions are emerging. As performance flaws arise, there is room for contention. If technology fails to function as intended, there will undoubtedly be time and monetary repercussions.
Large-scale hydrogen projects will likely require environmental impact assessments, licenses, planning approvals, and land-use agreements, similar to typical fossil fuel projects. Delays in overcoming license and regulatory processes can result in contractual chain issues.
Power purchase agreements and hydrogen offtake contracts may give rise to contractual issues. To assure the availability of reliable sources of energy and hydrogen, producers and end-users will need to do rigorous due diligence.
