The government has promised to provide £140 million in revenue support for hydrogen and industrial carbon capture projects. The support will be allocated via a new scheme which was announced in the government's Net Zero Strategy - the Industrial Decarbonisation and Hydrogen Revenue Support scheme. We explore how the scheme is intended to operate, its role in the transition to a carbon neutral energy system and the challenges facing hydrogen producers. As well as to what extent green hydrogen and blue hydrogen technologies will receive support under the scheme.
Will it create a new hydrogen market or reshape the existing energy market?
The Industrial Decarbonisation and Hydrogen Revenue Support scheme is not entirely new news. The Department for Business, Energy & Industry Strategy released a consultation paper on the scheme in August of this year. The paper sets out how it will enable the creation of a hydrogen market. This might prompt images of people gathering around old wooden carts bartering for the best price of hydrogen, whilst coal, grains and livestock are traded in the adjacent rickety, but nonetheless charming, stalls. Okay, maybe not quite, but are we really talking about a new market?
The intention does not seem to be to create a marketplace whereby hydrogen is bought and sold as a commodity, because in reality the net zero challenge means that its use as an energy vector will far outstrip its use in industry (e.g. oil refining and steel production). It appears that the scheme is actually focused on enabling the displacement of fossil fuels with hydrogen fuel. And so, perhaps instead of seeing the scheme as a means of creating a new market, it is more apt to view the government's policy aim as an effort to reshape an existing market – that is the energy market.
More Chickens and More Eggs
The absence of infrastructure for the storage and transportation of hydrogen creates a higher offtake risk for hydrogen projects, and is a significant barrier to the transition to an energy market with hydrogen at its core. This risk does not derive from a lack of market, so much as a lack of a network. Much like the chicken and egg scenario that beset the electric vehicle industry, the lack of infrastructure inhibits end-users from switching from using fossil fuels to hydrogen. Unlike the existing electricity and natural gas transmission networks, there is no national transmission system to get hydrogen to where it needs to be. Albeit trials are being undertaken by the National Grid to see if there is merit in converting decommissioned parts of the gas transmission network to hydrogen.
The current differences in levels of offtake risk across the energy market are highlighted when contrasting an electricity generator's experience of selling power against a hydrogen producer's experience. An electricity generator has the luxury of switching power purchasers with relative ease. No new infrastructure or connection is needed; the generator simply contracts and re-registers with a new purchaser, and uses existing infrastructure to export power in the same way. There is even a regulated offtaker of last resort for CfD generators if no market purchaser can be found.
Whereas, at least in the near future, connecting hydrogen producers to end-users appears to be dependent on the development of private networks with corporate offtakers. This is a big issue for investors and funders. They require certainty of offtake in order to be confident that producers are going to sell sufficient volumes of hydrogen to cover their costs (and, of course, provide them with a return on their investment). However, as has become apparent in the heat market, without a public sector purchaser, there is an inherent insolvency risk and consequently offtake risk that financiers are reluctant to take.
Putting aside differing perceptions of the government's aim, the scheme is designed to substantially reduce volume risk. When we refer to volume risk we mean the risk that the number of hydrogen units sold is lower than what is required to allow producers to recover their production cost. The scheme envisages that the subsidy will be applied using a sliding scale mechanism. This is where high levels of support are given to producers on initial volumes, allowing the producer to offset its fixed costs, and then support is reduced as volume increases.
It is worth noting that the government does not intend to support producers if their hydrogen sales fall to zero. In other words, hydrogen producers will continue to take offtake risk in the sense that they must always have in place at least one offtake contract. Meaning that the insolvency risk that financiers get so nervous about will not be completely eradicated, but somewhat mitigated. It remains to be seen if the volume risk mitigation that the government proposes to implement will sufficiently minimise offtake risk for investors.
The scheme is also intended to minimise price risk - the risk that the cost of producing hydrogen is higher than the price secured for selling it. It proposes to achieve this by adopting a variable premium price support mechanism. This is where the government enters into private law contracts with producers, pursuant to which the government pays the producer the difference between a reference price and a strike price. This is the same mechanism that the government used for the Contracts for Difference for low carbon electricity generation. The only material difference being that there is no equivalent wholesale electricity price for hydrogen. The government has proposed instead that the reference price is the higher of the natural gas price and achieved sales price. The idea being that this approach prevents market distortion because hydrogen is not subsidised for sales below the natural gas price.
What will success look like?
To be successful the revenue support model needs to reduce price risk and volume risk by compensating producers by just the right amount - enough to overcome the lack of confidence in the sale of hydrogen, but not too much that there is an over-reliance on government subsidies. This will require the scheme to flex according to changes in the energy market, and avert unintended consequences. Choosing a variable reference price helps with striking the right balance. It makes it possible for a market value of low carbon hydrogen to emerge relatively organically, where otherwise it might not. That is assuming that the natural gas price floor does what it was set out to do. However we know from recent spikes in the price of natural gas, that this may not always be the case. It begs the question of whether the scheme's inter-dependence on the natural gas price could cause under-compensation – a lot will depend on the extent to which the hydrogen price moves in lockstep with the natural gas price. It also circles back to the point that the intended effect of the revenue support model appears to be to embed hydrogen in the existing energy market, amongst other fuels, rather than to create a standalone hydrogen market.
Success will also be borne out of competition, because competition will get end-users the best possible price. There are aspects of the scheme where the government may fall short on this. Initially the government proposes to bilaterally negotiate the strike price, rather than by using an auction process (where producers bid the lowest strike price they are prepared to accept). Naturally the danger is that the lack of competitive tension results in the government being tied into contracts that over-subsidise producers. The government appears to double down on that risk by also proposing that the achieved sale price is part of the formula for determining the reference price. The result of that being that there is no incentive for hydrogen producers to increase the achieved sales price, given that the higher the sales price, the lower the subsidy. That said, the government acknowledges this deficiency in the mechanism and nods towards additional contractual measures being put in place (e.g. a gainshare mechanism that rewards producers for securing sale prices above the natural gas floor). As well as the bilateral negotiation process being used in the short-term only.
What technologies are covered?
Hitting the sweet spot on revenue support levels, so that in the words of Goldilocks it is 'just right', should stimulate investment. But to truly develop an energy market that is not dependent on fossil fuels, a sufficiently wide-enough variety of technologies will need to benefit from the scheme. The intention is for both electrolytic and CCUS-enabled projects (i.e. green and blue hydrogen respectively) to be supported. The key will be ensuring that not only the lowest cost technologies (at the time of contract award) are supported. The government acknowledges that they may need to ring fence support for particular technologies to avoid this, but generally they are of the view that policy should be solution agnostic; that the market should decide what sinks or swims. However, given that green hydrogen is on the whole currently more expensive than its blue counterpart, this intervention is likely to be necessary to allow space for greener technology to find a footing in the market.
The government is due to publish a response to their consultation on the scheme in Q1 of 2022, as well as indicative Heads of Terms of the business model contract. The first round of contract allocations, worth £100m, for electrolytic hydrogen production is set to take place in Q1 of 2023. A further allocation will be made in 2024. The end result being that up to 1.5GW of low carbon hydrogen contracts will be awarded under the scheme. In the longer term, ideally the scheme will enable a variety of hydrogen technologies to feature in the energy market, and ultimately contribute to the decarbonisation of the power, heat and transport sectors.