Green vs. blue: The precarious hydrogen balancing act

Hugo Lidbetter, energy partner at law firm Osborne Clarke, discusses the government’s twin-track strategy to low-carbon hydrogen production, the likely balance between blue and green hydrogen, and how this has been affected by recent events such as the war in Ukraine.

Unlike several European countries, the UK government is hedging its bets when it comes to the hydrogen economy.

By not backing a particular technology they have, at least partly, let the markets determine what the “green” vs “blue” hydrogen balance should be. That said, this government has a particular appetite for headline-grabbing gigawatt targets and the upgraded ambition in the Energy Security Strategy (to 10GW by 2030) carries with it a new assumption of a 50/50 mix.

This rebalancing is interesting, as the previous target was for 5GW of “low carbon hydrogen production capacity” by 2030 (as set out in the Energy White Paper), which most commentators expected to be dominated by blue hydrogen. Even so, the government now estimates that there is a pipeline of around 20GW of hydrogen projects in the UK – so the expectation is that the targets will continue to ratchet upwards as capacity comes online.

The confidence behind increasing the targets and the associated rebalancing of the main technology archetypes reflects the growing momentum of (and pivot towards) green hydrogen. Bearing in mind that the Energy White Paper, Hydrogen Strategy and landmark reports by the Committee on Climate Change (CCC) all positioned green hydrogen as the longer term solution (with blue hydrogen providing the intermediate production route), this reveals an interesting change in approach.

That said, there is currently little to suggest we will see the scales tip drastically in favour of green hydrogen. So why is this happening and where might things end?

Blue first on the grid

As mentioned above, the market expectation was that blue hydrogen would be the transitional route to green hydrogen, with blue being dominant over at least 2025-2035 and green taking over towards 2050.

This assumption was set by the government’s initial strategy papers (complemented by the CCC reports and National Grid’s Future Energy Scenarios), but also presents a credible solution to the projected hydrogen demand curve over that period, as blue hydrogen (at least in principle) scores highly for scalability and deliverability. The question of delivering blue hydrogen at scale is largely a capex one: the capture technology to add to the steam methane reforming process already exists, it just needs to be drastically scaled up and proved effective at commercial operating levels (admittedly, not small asks).

In principle, and once questions over capture rates and efficiencies have been addressed, that scalability could be delivered through a willing investor base with deep pockets and a sound revenue support model (more on which below).

In contrast, green hydrogen requires answers both to the question of how to scale currently low-capacity electrolyser technology and of how to optimally site and operate electrolysers (for example in zones of frequently curtailed onshore wind, with offshore wind or with baseload plant – such as nuclear). The early thinking here was that electrolysers simply relying on excess or “otherwise curtailed” wind or solar would be insufficiently utilised to deliver an attractive cost of capital. More recently, related concerns about price cannibalisation through electrolysers, battery storage, electric vehicles and interconnectors all competing for cheap power have surfaced.

Of course, the missing piece in this consideration of where blue hydrogen sat relative to green is the input fuel cost. Another coincident policy that helped put blue hydrogen firmly in pole position was the government’s willingness to wrap its decarbonisation strategy around heavy industry. There is a coherent economic attraction to decarbonising the most polluting industrial activities through co-locating the technological solutions with them (carbon capture and hydrogen production).

Similarly, this approach shows direct economic action against one of Net Zero’s “hard to abate” sectors, while slotting neatly into the wider policy narrative of “building back better” and supporting jobs in, and the future of, industrial heartlands and the so-called “red wall”.

All this comes together in the Government’s “clusters” strategy: that decarbonisation of industry, nascent carbon capture projects and high-volume blue hydrogen production can all sit cogently in energy-intensive sites, enjoying a synergistic dependency and underwritten by private gas networks of 100 per cent hydrogen.

The slide from blue?

So why the perceptible change in dynamic? The first and by far most significant development has been the post-Covid economic recovery and the subsequent war in Ukraine. These two events, or series of events, have pushed gas prices to record levels. From a blue hydrogen perspective, this has had two immediate effects.

First, reliance on imported gas, at any market price, now sits at odds with the revised focus on energy security (reflected in the Energy Security Strategy) over decarbonisation and Net Zero per se. There is a potential caveat here in relation to North Sea gas projects, although the reappraised importance of that sector was oddly bungled by the windfall tax debacle.

Second, the economics of blue hydrogen have had to be revisited, given the material movement in the cost of the primary input fuel. Various think tanks have recently produced reports recalculating the variables of, and modifying the assumptions behind, BEIS’s cost models for blue hydrogen.

Of course, to the extent that green hydrogen is grid connected and powered by grid-imported electricity (as opposed to co-located generation), it too is exposed to the rise in electricity prices (set by gas prices as the marginal cost fuel). But it is worth saying that the longer-term narrative of green hydrogen has never been to rely on grid power, at least not as the dominant input fuel. So the economics of green hydrogen projects have been dented too, but perhaps to a lesser extent.

Fitting into the energy transition

Another driver starting to emerge is the growing acceptance that green hydrogen plays very strongly into the existing narrative of a largely decentralised, intermittent power system. The problem with stacking blue hydrogen against a dominant wind/solar system is that gas, more generally in terms of where it fits into the mix, has to adopt that pattern- i.e. it effectively becomes an intermittent form of generation itself as gas generation will only be deployed at times of low renewable output.

This phenomenon exacerbates the existing challenge of encouraging new build gas-fired power stations, a specific aim of the capacity market and one it spectacularly failed to deliver.

Electrolysers, however, work with and around that intermittency – but only to an extent. A well thought through co-located project can right-size the electrolyser capacity to the wind/solar plant to maximise the overall generation potential of the site. Much like co-located storage, this offers many potential advantages (many of which are still to be proved): it optimises an existing grid connection, it may avoid additional network reinforcement, it supports energy security, it can avoid renewable energy “wastage” when wind would otherwise be curtailed and it opens up a wider range of optimisation avenues for the asset owner.

Of course, as above, the challenge will be how that new demand class (electrolyser capacity) interacts with other new types of demand for excess renewable generation such as battery storage, interconnectors and EVs.

The hydrogen business model: a nudge to blue?

As a final word on factors affecting the “green – blue balance”, it is worth touching on the government’s thinking behind the recently proposed hydrogen business model.

The determination to go with a one-size-fits all contracts-for-difference (CfD) approach has run the risk of pleasing no one, particularly with its complex two-tiered reference price mechanism. On the one hand, offering a CfD model predicated on compliance with the Low Carbon Standard risks making life difficult for blue hydrogen producers, while on the other, operators of smaller green hydrogen projects tend to regard a CfD regime as being unnecessarily complex and burdensome (in place of, for example, a fixed premium).

But the dominant theme is, once again, the government’s determination to accommodate both technology archetypes and not to run the risk of designing a solution specific to blue and green hydrogen individually. They are concerned this approach would add complexity, risk delay, potentially distort the market and introduce inefficiencies in the funding pot. As such, the funding model will be tinkered around the edges to reflect the specifics of each technology (for example allocation process, strike price and indexation) but otherwise, the hope is very much that as it worked for renewables/low-carbon generation, it should also work for hydrogen.

So, for now at least, the twin-track strategy continues – and the more accommodating industry view is that the target volumes and need to rapidly decarbonise will require all solutions, quickly and at scale. However, it will be very interesting to see how things progress as the early projects start to deliver.