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27 July 2022

UK moves forward with confused hydrogen strategy

The UK has pushed forward with plans to develop what it believes will be a world leading hydrogen industry. Despite strong strides to create the world’s first national hydrogen subsidy scheme, lines remain blurred between what counts as ‘clean’ hydrogen and what does not.

The 20th of July marked the opening of a new subsidy scheme in the UK, which aims to fund an initial 1 GW of green hydrogen and 1 GW of blue hydrogen projects. Support through the new Hydrogen Business Model (HBM), as well as up to £240 million of grant funding from the Net Zero Hydrogen Fund (NZHF) comes as part of a broader goal for the country to have installed 10 GW of low-carbon hydrogen production capacity by 2030 – enough to satisfy 4% of the country’s current energy demand.

The new scheme will use a similar contract-for-difference (CfD) mechanism that has incubated the growth of the UK’s leading offshore wind sector. The CfD operates on the principle of certainty of energy pricing for a developer, which can be invaluable in the early stages of such emerging technologies with high upfront costs and long investment lifecycles. It protects both developers and consumers from paying support costs when electricity prices are high or volatile.

CfD contracts are allocated through a process where the lowest project bids are awarded contracts first within each technology group. If the awarded bid price is above the market price, the state will be required to pay the difference, and if it is lower, the difference will be paid by the developer back to the state. This means that successive bids tend to get closer and closer to a parity position with fluid energy market prices. In the UK, the scheme’s competitive nature has seen the price of offshore wind fall by around 65%, hitting prices of £40 per MWh in the last auction.

The HBM will offer a similar ‘variable premium price support model,’ which will provide project owners with a subsidy that represents the difference between a pre-agreed strike price and a ‘reference price,’ tied to the market price for grey hydrogen produced using natural gas. It also includes volume support, where the strike prices are higher on a per-unit basis if hydrogen offtake fails.

Delivery of the NZHF will be split into four categories. The first offers a 50% grant for development expenditure; the second offers up to 30% of co-funding support for the Capex of smaller projects that do not require assistance through the HBM; the third will help offset the Capex of electrolyzer projects that receive HBM support; the fourth will address the capex of CCUS-enabled projects.

Much of the funding will go towards the two planned hydrogen clusters in the UK: HyNet, in the north-west of England, and the East Coast Cluster near Teesside, both of which will focus on the decarbonization of things like fertilizer and steel production.

The first stage of the application process is specifically for green hydrogen projects – referred to as ‘electrolytic’ hydrogen by the UK government, as projects may be powered by grid-electricity, or non-renewable energy resources. Developers now have until the 7th of September to register their interest, with allocation of the first 250 MW scheduled for 2023. A subsequent round will open in 2023, before allocation in 2024. Final applications for funding must be filed by 12 October.

This schedule aims to see the UK have up to 2 GW of ‘low carbon’ hydrogen production capacity in construction or operation by 2025, with at least 1 GW of this coming from ‘electrolytic’ sources.

The half-blue, half-green approach is something that the UK foresees continuing through to 2030, with 5 GW of each type of production outlined in the country’s Energy Security Strategy that was unveiled in April.

The issue comes with this definition of ‘low-carbon.’ Within the HBM, this is defined as hydrogen that is produced with less than 2.4 tons of carbon emissions for every ton of hydrogen produced. It is mandated that this measurement will also include upstream emissions, which – in most instances – will rule out blue hydrogen altogether.

One study from the Universities of Stanford and Cornell have highlighted that while some CO2 emissions may be captured, the huge amount of natural gas used in the production of hydrogen – around 2.7 tons of methane per ton of hydrogen produced – lifecycle emissions of ‘fugitive’ methane are still overwhelming.

Methane leaks and emissions from wells and other equipment, accounting for around 3.5% of the total natural gas used across the blue hydrogen supply chain, nearly completely offset the benefits from capturing 85% of CO2 from steam methane reforming.

Even if you make the tenuous assumption that 85% of carbon emissions can be captured and stored indefinitely at a blue hydrogen production site – bearing in mind that figures today are often as low as 10% – the process to make blue hydrogen takes a large amount of energy, which is generally provided by burning more natural gas.

While blue hydrogen is likely to reduce emissions compared to existing methods of grey hydrogen production, this will only be in the region of between 9% and 12%, once you combine the uncaptured CO2 and the large emissions of unburned, so-called “fugitive” methane emissions inherent in using natural gas.

The report is not the first to try and expose blue hydrogen as a misleading route to a decarbonized economy. In April, a study from think-tank E3G argued that the process should be restricted due to the high cost and the risk of “locking in” fossil-fuel use for decades to come. It also pointed to the vast greenhouse gas emissions due to methane leakage along the value chain. Canadian think-tank Pembina Institute has also estimated that each ton of blue hydrogen would result in between 2.3 tons and 4.1 tons of CO2 equivalent.

Leakages are historically underestimated and underreported, with satellite technologies now starting to reveal huge plumes, which had previously been undetected. The IEA estimates that even if all available solutions were to be deployed across value chains, 25% of total oil and gas methane emissions would remain unaddressed.

All of this makes it extremely worrying that countries like the UK are taking a ‘twin-track’ approach to hydrogen development, remaining agnostic to whether blue or green hydrogen will be central to its future hydrogen economy. The umbrella term of ‘low carbon’ hydrogen is a classic tactic to slide blue hydrogen past environmentalists.

Lauding blue hydrogen as a clean gas, or even as an interim solution, is a distraction tactic that the oil and gas industry is using to divert attention away from true decarbonization. The discussion is currently dominated by those with interest in oil and gas infrastructure. Following this line of thinking will leave countries dependent on natural gas imports and will allow these laggard companies to continue with business-as-usual approaches for years to come.

Blue hydrogen will come with a higher strike price than green hydrogen in the long run. This will be a particular issue beyond March 2025, when support is planned to switch to become levy funded and added to consumer energy bills.

It also relies on natural gas for its production, which needs no further demonstration of its price volatility and insecurity in supply. Around half of the UK’s gas is imported from overseas, so a shift towards blue hydrogen would only decrease the energy security that the country is so desperately seeking.

The only case for blue hydrogen is that it will allow hydrogen infrastructure to scale while there is insufficient renewable energy capacity to drive a build out in electrolysis. Producing 10 GW of green hydrogen would require around 126 TWh of renewable electricity – around 40% of the UK’s total supply.

However, instead of investing in a transition fuel, which is bound to create billions of pounds worth of stranded assets, the UK should invest in building the renewable energy capacity needed for all of its energy needs. Reinstating momentum behind the country’s onshore wind sector, while increasing activity offshore, will be essential. As will decreasing demand from a consumer level through immediately accessible means such as insulation.