Research to understand the relationship between deploying domestic hybrid heating technology and hydrogen supply to achieve an optimised energy strategy.
Objectives
The objective of the project is to assess the combined energy demands of a select region within GB and understand how the deployment of hybrid heating technology in combination with bulk hydrogen supply is able to achieve carbon compliance with respect to national carbon targets.
The primary outcome of the work will be to provide intelligence on how these two technology vectors interact within a compliant energy system to inform business plan development and allow wider regulatory/policy stakeholders to be engaged.
Learnings
Outcomes
The outcomes of the project have been broad and far reaching and have informed and supported the formation of our Net Zero vision.
Domestic Heat Global Optimisation
The overall household spend on energy was found to be not materially different between a 100% hydrogen heating scenario and scenarios with electrification representing up to 75% of heat via full deployment of hybrid heating systems. The fundamental reason for this is the balance of capex and opex – although the incremental introduction of hybrid heating systems has a greater capital cost than a gas boiler, the overcapacity of wind generation within a Net Zero system, in combination with a coefficient of performance of the heat pump and partially electrolytic hydrogen supply (15% of hydrogen supply), results in the opex of the hybrid being lower. This economic balancing extends to the full deployment of hybrid heating, resulting in material electrification that could be delivered at little marginal cost to the consumer. Although total cost per tonne of carbon abated was broadly the same across all hybrid deployment scenarios, indicating no stand out optimum economic deployment, there would be material benefits in a hybrid-first strategy as the cumulative carbon emissions along the pathway to NetZero would be lower. This would be achieved by the hybrid soaking up any genuinely low carbon electricity available for heating, as generation and storage capacity is deployed.
The maximum electrification capacity of heat via deployment of hybrid heating systems was found to be 75%, with the hydrogen boiler representing the final 25% of heat delivery. To electrify the remaining 20% of heat, the heating systems would require replacement with full heat pumps systems. The resulting total cost per tonne of carbon abated for 100% hydrogen and 100% hybrids was found to be around £100/t for both scenarios, and up to £1,000/t under a 100% electrification scenario, due to requirements to satisfy peak heating demands. The overcapacity requirements of generation, storage, transmission and distribution assets necessary to supply peak heating demands resulted in a significant general reduction in asset utilisation. This manifested itself as a greater cost to consumers as overall utilisation reduced over the course of asset lifetimes. A series of alternative scenarios were modelled using different production technologies to supply the additional electrical capacity required by a 100% electrification solution, this sensitivity analysis was undertaken on the 100% electrification scenario to understand the resultant implications of leveraging different generation technologies to provide peak heat requirements.
Hydrogen-Hybrid Coupling Benefits
Material coupling benefits were identified from the co-deployment of hybrid heating technology and hydrogen supply. These benefits most principally pertain to the deconstraining effect of hybrid heating on the logistics of hydrogen supply. The capacity of hydrogen required to satisfy a given gas demand was found to reduce with the deployment of hybrid heating systems, this is because domestic gas consumption reduces as the hybrid particularly electrifies the heating supply. The regional production capacity for necessary hydrogen supply was found to vary between 320 MW and 610 MW between a 100% hybrid deployment and 0% hybrid deployment scenario respectively, therefore if any regional constraints exist around hydrogen capacity, this could be alleviated by hybrid deployment. The quantity of carbon dioxide tankers (10,000 tonnes each) required to facilitate the reformation-based hydrogen production reduced from 70 per year to 35 per year as hybrids were deployed, this is due to the reduced capacity of hydrogen production required to satisfy the total gas demand. A fully hybridised domestic heating solution (100% hybrid deployment) results in a 50% reduction in tanker requirements – down to 35 per year. This was calculated to identify any potential logistical constraints of carbon dioxide shipping to a carbon capture, usage and storage (CCUS) pipeline elsewhere around the UK – which was taken as the regional CCUS strategy for Cardiff given the lack of depleted oil and gas assets in the immediate proximity to the region.
Low Cost Hydrogen Supply
Regional hydrogen supply was found to be low cost. The dominant supply vector being natural gas reformation-based technologies, as indicated by the CCC Net Zero report. This supply vector was found to be < £50/MWh, inclusive of the production assets, CCUS infrastructure and carbon dioxide shipping. This figure is in line with third party assessment and used FOAK economics for conservatism, indicating the potential for cost reduction through to 2050. The current support price for biomethane supplies, as per the Renewable Heat Incentive policy is £60/MWh, therefore reformation-based hydrogen was found to be a low-cost, low-carbon gas supply.
The balance of generation and storage via salt caverns was assessed to understand the optimum mixture of assets for minimum overall capital investment. This balance used third party sources for the capital cost of each element and identified the optimum mixture being a balance where only critical storage is invested in and average load factors of generation assets is ca. 60%. The contribution of capital investment to the levelised cost of hydrogen is a minority influence, with over 70% of the levelised cost attributed to operating costs (most principally feed costs), this is the fundamental economic characteristic that promotes the overcapacity of hydrogen production assets when finding the optimum balance of production and storage.
Lessons Learnt
One of the key lessons learnt from the development of the HyHy project was the need to engage early with key stakeholder groups that a project seeks to provide value for. By engaging early, as was done, the project was able to take on board valuable feedback from key stakeholders and incorporate their insights and perspectives into the structure of the project, instead of waiting until final dissemination to assess feedback. This open approach to stakeholder engagement ultimately allowed the project to produce more value for key stakeholders and the industry at large, which should be a key lesson for any scenario modelling project.
Another key lesson learnt from the project is associated with the need to progress efficiently through the programme to allow information and key initial conclusions to be known with enough time to undertake sensitivity modelling of the final conclusions. This management process of providing sufficient time for results-based sensitivity analysis maximises the ultimate value of any scenario modelling-based project as the contextual energy system information of the final solution can be evaluated and understood to frame the final conclusions.
