United Kingdom | Publication | August 2023
Between August and December 2022, the government consulted on design options for two new business models to support the development of hydrogen transport and storage (T&S) infrastructure in the UK, recognising that a supportive policy framework is necessary to encourage investors in projects facing long lead times, high capital costs and hard-to-predict investment returns. The T&S infrastructure business model consultation was run alongside questions on the need for strategic planning, regulatory reform, and the potential of allowing hydrogen to be blended into the existing gas grid. The consultation forms part of wider government planning to stimulate the development of the hydrogen economy, ultimately working towards achieving its net zero ambitions.
In its response, published on 2nd August and entitled “Hydrogen transport and storage infrastructure: minded to government positions on business model designs, regulatory arrangements, strategic planning and the role of blending” , the government has put forward it’s “minded to” positions on all five aspects of the consultation (the transport business model and storage business models being treated separately). While it is clear that regulatory reform and the role of blending require more detailed thinking and consultation, there has been significant progress on the business model designs and an acceptance that strategic planning is a necessity. In this briefing, our energy counsel, regulatory specialist and director of energy knowledge, Penny Cygan- Jones, summarises the key take aways that developers of hydrogen transport and storage infrastructure need to know, and highlights what to look out for next.
Hydrogen transport infrastructure A RAB will form the basis of the business model (as it is a well-known model for both regulators and likely investors, which will help to de-risk). Government will allocate and negotiate the RAB via gas transporter licences initially, with Ofgem to take over at a later date. In addition to the detail of the business model design, government still needs to develop its position on allocation of support and the accompanying market framework for early projects.
Hydrogen storage infrastructure Initial focus for support will be geological storage, with an option to support above-ground storage in future. Design will include a revenue ‘floor’ to mitigate demand risk for storage providers, an incentive to maximise sales to users, and a mechanism to give the subsidy provider a potential share of the ‘upside’. Storage support will be delivered via a bilateral private law contract (Hydrogen Storage Contract) with a term of at least 15 years. The next step will be further work on the detail of the business model, as well as developing the government’s position on allocation of support.
The HPBM and NZHF jointly support the Hydrogen Allocation Rounds. HAR1 is currently underway; round 2 is expected later this year.
Both of these business models are due to be in place by 2025.
Government has reaffirmed its commitment to providing a business model by 2025 and has ruled out any interim business model being put in place until then. The initial target of any support will be large-scale pipeline infrastructure, mainly onshore, as early projects are expected to produce and use hydrogen in gaseous form and are mainly located onshore. The focus for moving this gas will be via pipeline, as, based on the Frazer-Nash analysis published in 20222, transport of hydrogen by pipeline will be far more competitive than by road (levelised costs by pipeline = approx. £0.17/kg; by road = approx. £1.23/kg). Views were also sought on other types of infrastructure and methods of transport, including offshore pipelines (but note the response to a separate consultation on this due is to be published in Q3), and transport of hydrogen via vehicles, or via pipelines as ammonia.
For initial producers and end-users with limited hydrogen transport requirements, support can be sourced instead from the hydrogen production business model (which will offer capex only support).
A Regulated Asset Base (RAB) will form the basis of the business model (as it is a well-known model for both regulators and likely investors, which will help to de-risk). An external subsidy mechanism will be created alongside a RAB to address low user numbers as the industry develops. This should effectively “top up” the difference between allowed revenue and the amount that can be recovered through “fair” user charges, to mitigate against initial high user costs which would disadvantage early users or dissuade them from entering the market. The external subsidy mechanism will be delivered through a private law “Hydrogen Transport Revenue Support Contract” between a government counterparty (yet to be confirmed) and a hydrogen transport provider, and can be used in conjunction with or separately to a RAB. No decision has yet been taken with regards to how the external subsidy mechanism will be funded. Options for funding include money from the Exchequer and/or a levy, and detail on this, including how to fund any such levy, will follow in due course.
The aims of the business model are to provide sufficient predictability over revenue and return to investors (but not facilitate excessive profits); mitigate risks that investors are not best placed to bear; incentivise transport providers to optimise the use of their infrastructure, and encourage the development of a market, through cost reductions and certainty for users, that does not require on-going support. It will be designed to be compatible with the future natural gas network price controls, to help with facilitating the repurposing of existing infrastructure, asset valuation and risk management. The long-term goal is a reduction in government support as the hydrogen economy grows, eventually transitioning to become subsidy-free.
Currently RABs for natural gas networks are allocated and implemented through gas transporter licences granted under the Gas Act 1986 (the “Gas Act”). Hydrogen is a gas within the Gas Act. Under the Gas Act, Ofgem is already the independent regulator for hydrogen, and the Energy Bill currently going through Parliament proposes that Ofgem is also the regulator for carbon capture T&S infrastructure.
A licensing framework for establishing price controls could therefore be managed by Ofgem, via the mechanics of the Gas Act, although there is recognition that some further legislation may be required to account for differences between hydrogen and natural gas. However, reliance on the Gas Act will enable government to act more quickly in getting the first large-scale projects up and running. There is also recognition that for first of a kind projects, the licences should not be granted and regulated solely by Ofgem. Selection of projects and their strategic importance will be linked to decisions being made by government on hydrogen production business model allocation rounds, as well as wider decisions around sequencing of the low carbon clusters. It is therefore the government’s view that it (via the Secretary of State for the Department for Energy Security and Net Zero (DESNZ) and pursuant to the Energy Bill) will be better placed to manage allocation of RABs in early hydrogen pipeline projects. The next stage of work on the business models will include consideration of the configuration of roles and responsibilities between Ofgem and government.
Strategic planning will form the basis of the business model allocation process, taking into account location, project size and timing, and also future as well as current predicted demand. It is expected that the licence will be granted after bilateral negotiations between DESNZ and prospective hydrogen transport providers, with a key role for the regulator and the counterparty until such time as Ofgem can take control. In the longer term, it is likely that strategic planning for allocation will be managed by the Future Systems Operator (FSO), a function being established via the Energy Bill.
Three broad types of hydrogen storage exist – geological (e.g. salt caverns, depleted gas fields); above-ground (for liquefied or gaseous hydrogen); and chemical (ammonia, methanol, metal hydrides). Each of these were considered for support with geological storage being selected. The focus on geological storage is seen as a better fit for government objectives on scale, technological readiness and end use. Geological stores are larger than other types, and consequently are more capital intensive, with longer development lead times (up to ten years) than above-ground approaches, and therefore unlikely to develop without government support. However, the intention is to design a single business model which is flexible enough to be used for all storage types, should market conditions dictate that other forms of storage need subsidy support in the future. It should also be noted that not all types of geological storage will be eligible - a minimum technology readiness level (TRL) will be set to ensure government supports projects that are technologically viable and ready for commercial scale deployment.
The priority for the storage business model is to provide sufficient certainty to prospective storage providers to enable final investment decisions on strategically important projects to be taken promptly, whilst at the same time ensuring value for money for government. In the longer term, government expects the hydrogen storage industry to be self-sustaining, with a large number of storage facilities and storage businesses forming a competitive market. It is keeping an open mind on whether there will be a need for on-going government intervention (e.g. maintaining mandatory levels of storage to ensure security of supply) but as with hydrogen transport, the ultimate aim will be to transition to a subsidy-free model.
The business model will be designed to provide protection against demand risk, divided into price risk (i.e. the risk of achieving a low sales price) and volume risk (i.e. low volume of sales). Demand risk is seen as the biggest barrier to investment as it is beyond the control of the storage provider, and so the commercial design will provide a minimum revenue floor to mitigate against this, most likely based on a minimum annual revenue and issued in instalments over the year. Storage providers will be allowed to earn above this amount to incentivise maximum revenue and encourage development of the storage element of the hydrogen economy. However, should revenues be particularly high, the government is considering a number of ways in which it could benefit from any upside to protect its “value for money”, including a cap on revenue (with excess given to the subsidy provider), a gain share mechanism, early termination of support by the storage provider, or perhaps the government taking an equity stake at business model award stage (and therefore receive either dividends or the benefit or an increased share value). All of these, in the alternative or in combination, remain under consideration.
The revenue floor over the entire length of the contract would be equal to the total capital costs of creating the storage facility, plus fixed operational costs, plus a (relatively low) return on capital investment. The floor would not cover variable operating costs, such as the cost of using energy to move gas in and out of the storage facility, as these are to be covered by users to the extent the facility is used. In order to incentivise maximum usage, although the subsidy would reduce in correlation to frequency of use, it would not be reduced by an amount equal to the increase. The net effect will be for storage providers to have an increase in revenue from an increase in usage (although the government response notes “the magnitude of the incentive for achieving sales to users will require careful consideration and be subject to affordability constraints and value for money”).
Other storage risks such as construction risk, technology risk, availability risk and decommissioning risk will all remain with the developer. The developer should be protected to some extent from change in law risk (to the extent any changes impact on use of hydrogen storage, as the subsidy will protect against demand risk) but further work is needed to allocate risks for force majeure and material adverse change events.
The current proposal is for support via a 15-year (at least), private law “Hydrogen Storage Contract” to be negotiated bilaterally between storage providers and DESNZ. It will include incentives during the operational phase for high availability (e.g. a reduction in the annual revenue floor if availability falls below 95%), and may also incentivise hitting key milestones during the construction phase, or set a target commissioning window, although this would depend on the type of technology used by the facility. It remains under consideration whether support might be provided for facilities built in stages, and how this might work in practice within the business model framework, but as an initial proposal the government would sign one contract covering all build stages, with payment for each phase commencing on completion of the relevant construction phase.
Government has also considered mode of ownership and usage. It may create rules to ensure the operational independence of geological storage facilities from other interests (similar to the existing rules for natural gas storage) and intends to further consider how users should be charged, whether services should be unbundled, and how prices might be set and change over time. The priority will be to ensure users are not charged excessively and the provision of a subsidy should protect against this, but whether this is achieved via conditions attached to the business model, or legislation and regulation, or both, is yet to be decided. Conditions such as independence from the interests of other energy systems or non-discriminatory third-party access, as already seen in the natural gas market, are obvious contenders.
Options for funding the business model, as with the transport business model, include money from the Exchequer or via a levy – and should it be via levy, the design will be subject to a further consultation.
Business model support will be allocated based on a number of criteria which are yet to be developed in full. Broadly they will comprise an assessment of storage use cases, a minimum TRL, location, proximity to hydrogen transport, and projected users/demand.
Note this chapter of the government response is supported by an annex which sets out rationale for options that were rejected for mitigating demand risk (Annex A on page 56), which is helpful in understanding which options are definitely off the table.
The first update on the detailed design of the business models will be published by the end of this year, in order to remain on track for T&S infrastructure funding awards to be made in 2025. Interested parties will be invited to submit further feedback.
An update on strategic planning for hydrogen will also be released by the end of this year. Strategic network planning will inform the allocation process of the T&S business models, in conjunction with the low carbon cluster sequencing process, and initial focus will be on areas which will help with building investor confidence and accelerating growth. Allocation will need to be coordinated across different types of assets, taking into account the energy system as a whole. For those investors seeking business model funding, we recommend looking out for future government publications (see “What else will help developers to understand the plan for hydrogen transport and storage infrastructure in the UK?”) to help ensure hydrogen business plans remain aligned with government priorities.
The HPBM and NZHF jointly support the Hydrogen Allocation Rounds. HAR1 is currently underway; round 2 is expected later this year.
Both of these business models are due to be in place by 2025.
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