CATF Response to UK consultation on hydrogen blending into GB gas distribution networks

CATF provided comments on the UK consultation on hydrogen blending into GB gas distribution networks. Our response focused on the strategic role of blending (Question 3). 

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1. Blending low-carbon hydrogen into natural gas pipelines wastes this scarce commodity and diverts efforts away from effective economy-wide decarbonisation.   

Hydrogen is not naturally abundant and to attain significant quantities of the molecule, it must be liberated from a compound form. There are two main production pathways for low-carbon hydrogen: water electrolysis and steam/autothermal methane reforming (SMR/ATR) with carbon capture and storage (CCS). Despite a plethora of recent project announcements, low-carbon hydrogen from both sources is currently in short supply and most hydrogen production today (>95%) is sourced from unabated SMR. In 2022, water electrolysis accounted for only 0.1% of global hydrogen production¹, mainly due to the prohibitive economics of this production pathway but also due to an undeveloped supply chain. 

Both production pathways require significant time for design, planning, permitting, and delivery. While supportive financial incentives and policies are set to change this picture in the near term, significant hurdles remain. Large-scale hydrogen production facilities are capital intensive. For water electrolysis, an abundant and stable supply of clean electricity is required, and for SMR/ATR with CCS, highly effective carbon capture systems with relevant supporting infrastructure (such as CO₂ pipelines and geologic storage facilities) must be ensured.  

Due to hydrogen’s physical properties, it is energy-intensive to produce and difficult to transport and store. These factors contribute to high production costs and therefore explain the current scarcity in low-carbon hydrogen. Due to this limited availability, both in present day and projections in the near-team, CATF recommends that low-carbon hydrogen deployment is prioritised in ‘no regrets’ end-use sectors, where there are simply no other alternative decarbonisation options, or where alternatives are technically or economically less feasible (figure 1). Future investments and markets for low-carbon hydrogen should take these prioritisations into account, ensuring that hydrogen is available for the sectors most likely to need it. 

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Figure 1: CATF ranking of potential hydrogen end use sectors (source: CATF) 

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Blending low-carbon hydrogen into the gas grid would dilute the environmental benefits of a scarce commodity that could be put to better use in other required sectors. Of higher priority should be industrial consumers – including refineries and ammonia producers – who produce some of society’s essential products, such as transportation fuels and agricultural fertilisers. These production facilities run around the clock and therefore require a steady supply of hydrogen for feedstock purposes. To meet high demand, refinery owners sometimes build their own on-site hydrogen production facilities but may also outsource hydrogen supply “over-the-fence” from nearby external suppliers, as is the case for many refineries in the United States. In either case, all aspects of hydrogen production are closely coordinated with the industrial off-taker, including volume, quality, uptime, and project lifetime. This should be no different in the case of low-carbon hydrogen, regardless of its production pathway.  

It is imperative that current uses of hydrogen, which are largely industrial users, be the first benefactors of low-carbon hydrogen supply in addition to new industrial users – such as steel manufacturing or sustainable fuels production – where low-carbon hydrogen can play an important role in the near future as their nascent markets develop out. 

2. Positioning the natural gas grid as a hydrogen off-taker, even on a temporary basis, will risk distorting the low-carbon hydrogen market.  

Low-carbon hydrogen developers must ensure that their projects are bankable, largely underpinned by projected revenue from off-takers. As highlighted in section 1, low-carbon hydrogen should be prioritised to the largest consumers of unabated hydrogen today, primarily industrial off-takers. Without this approach, it may create a volume risk – a risk that a hydrogen producer may be unable to sell enough volumes of hydrogen – as identified by the UK government². However, this risk is unlikely to materialise if development of low-carbon hydrogen production is closely tied to industrial off-takers. 

The UK Government will need to ensure that there are safeguards in place ensuring that hydrogen producers do not simply produce hydrogen and inject it into the grid on the basis that they do not have any off-takers, which would risk distorting the low-carbon hydrogen market. Instead, the UK Government should support low-carbon hydrogen developers in identifying and connecting to priority off-takers in present industrial applications. The UK Government should also consider how transitional grid injection will be enforced, for example through a statutory limit on hydrogen injections into the grid. 

3. Electrolytic hydrogen from curtailed renewable electricity should be prioritised for use as long duration energy storage.  

Electrolytic hydrogen production from curtailed renewable electricity is related more to proper power system design than to hydrogen generation. This has been demonstrated by a recent Royal Society report³, where the power system was specifically designed to deliver electricity in excess of demand and that excess electricity was used to generate and store hydrogen.  

Furthermore, independently planning and developing an electrolysis facility purely to capture curtailed electricity is not a profitable venture, due to low utilisation of the electrolysis facility and the unpredictable nature of curtailment. Even if the electrolysis facility is planned to balance renewable generation, the intended use of the generated hydrogen would be as a form of long duration energy storage to generate electricity when renewables are offline. The use of electrolysis facilities to generate hydrogen from curtailed electricity should be planned as part of an integrated power system design. Figure 2 shows electrolytic hydrogen prices⁴ relative to electrolysis capacity factors (expected for curtailment events). 

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Figure 2: Hydrogen production costs as a function of capacity factor and electricity price (source: CATF) 

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As such, the premise of injecting hydrogen from curtailed electricity into gas distribution networks does not hold. Electrolytic hydrogen generated by curtailed electricity is much better positioned to serve as a form of long duration energy storage in a largely decarbonised power system.  

It will be important for the UK government to clarify guidance on what forms of contractual agreements will take place, and to specify an off-take price that will ensure a reasonable return for the developer, while simultaneously – and more importantly – protecting the government from incurring unreasonable expenses in the quest to support this nascent industry.  

Also worth noting is that if the electrolysis facility is originally built to provide hydrogen to an off-taker, it is unlikely there will be spare capacity in the plant to accommodate curtailed electricity. As such, this scenario is not expected to contribute a large volume of hydrogen. 

4. Injecting hydrogen into the gas distribution system creates uncertainty and risk, and blending for residential applications is not a sensible or safe end-use.   

CATF urges the UK government to consider the wider implications of putting hydrogen into the natural gas system. The consultation does not specifically outline the intention or purpose of such blending, so CATF’s response focuses on two applications where hydrogen may be being considered: heating in residential and industry settings; and power generation. 

Numerous independent studies⁵ have concluded that alternatives such as heat pumps, solar thermal systems, and district heating are more economic, more efficient, less resource intensive, and have a smaller environmental impact compared to hydrogen when it comes to options for home heating. In addition, though hydrogen is routinely handled in industrial applications, its use in residential settings presents potentially serious safety hazards, both because of hydrogen’s high susceptibility to leakage (without a visible flame or odorant) and its flammability range, which is six times that of natural gas. The consultation document (p.27) references these safety concerns for home heating and residential applications and for these reasons, hydrogen should not be considered as a decarbonisation option for residential use.  

Both the UK government’s top infrastructure advisor and the National Infrastructure Commission⁶ have spoken out against the use of hydrogen for home heating, stating that it should be ruled out. A recent E3G report⁷ also provided strong argument against the UK Government’s blending proposal, concluding that blending does not encourage strategic deployment of hydrogen in sectors where it is the primary option for decarbonisation and furthermore runs the risk of locking in hydrogen for inefficient uses, such as domestic heating, at the expense of other sectors. Additionally, the report found that hydrogen blending could increase household and industry energy bills anywhere from 7-20%, and overall derail domestic heat decarbonisation efforts by delaying investment and strategy decisions in other more promising technologies.   

The consultation document (p.42) identifies potential challenges and risks associated with hydrogen blending, including the cost of updating legacy gas meters; possible embrittlement of old iron mains in the GB gas distribution network; and potential costs associated with deblending. The consultation also indicates that there may be safety concerns around the use of hydrogen blends up to 20% by volume in the GB gas distribution networks. Therefore, thorough evaluation and assessment of the safety implications of hydrogen blending is required before any planning seeks to commence.   

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Figure 3: Lifecycle emissions for hydrogen and natural gas fuel mixtures (kgCO_2e/MWh_e) (source: CATF) 

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In the case of power generation, figure 3 shows the lifecycle GHG emission reduction for various hydrogen and natural gas blends for use in a natural gas combined cycle plant. For 20% volume blends, the lifecycle GHG emissions only reduce by 7% compared to power generation by unabated natural gas, therefore diverting scarce low-carbon hydrogen for minimal GHG reduction merits.