The UK Government has promised to make a strategic policy decision in 2023 on whether to allow the blending of up to 20% hydrogen into the GB gas grid. Spoiler: this isn't the decision, but it's a consultation that will help them make the decision so if you are a hydrogen producer or a gas distribution network operator you should read and respond to it. The consultation looks at whether there is potential strategic and economic value for blending hydrogen, and if it is safe. It discusses the commercial support that government may offer to hydrogen producers selling hydrogen for blending. It also discusses how to implement blending, including billing arrangements and injection points.
Blending hydrogen into the GB gas grid
Developing the hydrogen economy is a UK government priority, as set out in policy documents like the Ten Point Plan, Hydrogen Strategy, Net Zero Strategy and the British Energy Security Strategy.
But to grow the hydrogen economy we need a market for hydrogen (see our Insight, Creating a new market from scratch: the UK hydrogen strategy) which is where hydrogen blending comes in.
The Government sees two strategic roles for hydrogen blending:
- As a reserve offtaker. Even if this is never used, having the option to sell hydrogen into the gas grid mitigates the volume risk for hydrogen producers if their usual offtakers can't buy the hydrogen or the transport and storage infrastructure is delayed. This should lead to lower investment costs.
- As a strategic enabler for certain electrolytic hydrogen producers to support the wider energy system. As an example, say there is an electrolytic hydrogen production plant planning to locate in NE Scotland and connect to an offshore wind farm to produce hydrogen from electricity that would otherwise be curtailed. The plant has no definite offtakers at this stage but can make a commercial case relying on selling hydrogen for blending before larger-scale transport and storage infrastructure opens new markets for it.
Interestingly, the Government stresses that the primary strategic role of blending is NOT to decarbonise the existing gas network and facilitate a transition to heat decarbonisation . And a decision on 100% hydrogen for heat is not contingent on a decision on blending. In fact, blending 20% hydrogen by volume into the GB gas distribution networks could generate carbon-savings of only up to 6-7%.
The preferred option is to add blending to the Hydrogen Production Business Model. The Government recognises it will need to design support so that it doesn't disincentivise production plants from finding new offtakers. Blending should be an offtaker of last resort if there is no other market for the hydrogen.
The Government prefers to let the market decide where to inject hydrogen into the grid, rather than have a centralised planning model where injection is only allowed at certain points. This is because producers, wherever they are based, need to have the option to sell for blending as reserve offtaker.
To allow maximum flexibility, the Government is minded not to set a fixed percentage that can be blended. It will go up and down depending on the market. The Government does not envisage it getting up to 20% in reality. It could even be zero, as long as the option is there.
Gas shippers and gas DNOs will be able to buy and sell hydrogen, as they do natural gas.
But shippers would not be able to sell on any low carbon hydrogen certificates for blended hydrogen, as this could create a commercial incentive for hydrogen producers to sell hydrogen to gas shippers for blending instead of to other offtakers. (This is because if the certificates were tradeable the gas shippers would pay a price premium as they could onward trade to suppliers/retail market and extract further value in the form of low-carbon energy products and tariffs).
To allow blending of more than 0.1% hydrogen (the current legal limit), the Gas Safety (Management) Regulations 1996 (GS(M)R) will need to be amended. But billing arrangements can continue as currently, as they are based on the calorific value of the gas, not on volume.
A strategic policy decision on whether to allow hydrogen blending is due in 2023 – so not long left. But that is no guarantee that any blending will take place. This depends on the economic case which itself depends on the safety case (if it is going to be very expensive to make the network safe to carry hydrogen, that will impact the economic case).
The consultation says that if the outcomes from the strategic policy decision, the blending safety review and any subsequent review of the economic assessment support a decision to enable blending in the GB gas distribution networks, DESNZ would then look to start the legislative and regulatory process to implement this, as well as the process to make any physical changes to GB distribution networks that may be required. Given the timelines for this work, DESNZ do not anticipate blending at a commercial scale to commence in GB before 2025-26, at the earliest.
Whether blending could be beneficial for a project will depend on a range of factors, including the planned location, the availability of hydrogen transportation to reach appropriate injection points on the gas network, and the distance to those injection points. Even for projects which do face some volume risk, blending may not be economically viable if a production plant is located far from an injection point, or where the costs of injection point infrastructure are high. So you should be checking if it would be feasible for you to inject into the gas network when deciding where to locate a project.
Individual projects can apply for an exemption to the GS(M)R to inject hydrogen onto a local grid but will need a full safety review (with lots of evidence required) and will only get a time-limited exemption.
The primary strategic role of blending is NOT to decarbonise the existing gas network and facilitate a transition to heat
If you need any help in responding to the consultation, please get in touch with any of the contacts listed.
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