Reflections on CREDS webinar ‘Decarbonising Heat Demand: a Scottish Case Study’ by researcher Daniel Scamman
How difficult is the challenge of heat decarbonisation? What are the implications and costs for electricity networks? How does this vary in different parts of the UK? What are the implications for my own research, modelling heat decarbonisation pathways as part of the CREDS Heat Challenge?
These were all questions I had when I tuned into the recent CREDS webinar Decarbonising Heat Demand: a Scottish Case Study with Professor Stuart Galloway and Jonathan Bowes of Strathclyde University, held on 4 November. Stuart has been researching the network implications of changes in demand for a number of years, and this includes the decarbonisation of domestic heat and the associated technologies. Jonathan is contributing to this research through a fellowship supported by ClimateXChange (opens in a new tab), an organisation that brokers relationships between academics and policymakers in Scotland.
The decarbonisation challenge
Stuart began the well-attended webinar by outlining the scale of the heat decarbonisation challenge in Scotland. A whopping 50% of final energy in Scotland is used for heating. Scottish targets are slightly ahead of the rest of the UK’s too – a 75% emissions reduction is required by 2030, equating to the decarbonisation of around 1 million homes (out of a total of 2.62 million [i]). Yet Scotland has a limited number of powers for meeting these targets, with some matters devolved (e.g. heat and energy efficiency) but not others (electricity networks). Additionally, the next price control period (RIIO-ED2) will run from 2023-2028, leaving network companies only 6-12 more months to forecast their spend during this crucial run-up to 2030. This involves not only predicting the impact on networks of the electrification of heat, but also of distributed generation and electric vehicles (even more important now that the ban on new petrol and diesel cars has just been brought forward to 2030 [ii]). A number of technology options for heat decarbonisation exist, but all have their strengths and weaknesses (as we ourselves found recently on the CREDS Heat Challenge [iii]). Stuart argued that biomass might not make a large enough contribution, that district heating requires low-carbon heat sources, and that hydrogen might be the best long-term option but not in time for 2030. This leaves heat pumps playing a huge role in decarbonising heating in Scotland to 2030 and beyond.
Jonathan then took us on a whistle-stop tour of heat pumps and network charges to explain their impact on demand and local networks. A typical 5 kWth domestic ASHP might consume as little as 1kW of electricity. [iv] However this could increase to 2.4 kWe under peak winter conditions, and if delivering heat at a high temperature to avoid radiator upgrades. A 3 kW backup heater could increase peak electrical demand to 5.4 kWe. Adding an EV charger (7 kW), peak domestic demand could rise to 14–20 kWe, enough to need upgrading the domestic fuse to 100 A. Service cables to the road are typically 24 kW; if this also needs upgrading, total “single use asset” costs (fuse plus service cable) payable by the home owner could be around £1000.
Additionally, users may have to pay a Reinforcement Charge if an upgrade in the local network (up to the local primary substation) is required or was needed in the last 10 years. This cost is shared with other local users and could average an additional £1000 – but could be higher e.g. if it involves digging up a road in a city centre or replacing a long network section to a rural customer. This may be avoided if there is enough existing headroom in the local network (so being a first mover might pay!). Upgrade costs higher up the network are called Use of System (UoS) Charges, but these are socialised and added to everyone’s bill (with UoS charges typically 25% of electricity bills). However, if only the wealthy can afford to install heat pumps and EVs, the less well-off will still have to pay for these top-level upgrades they don’t use. Hence total upgrade costs can vary significantly between users depending on the existing capacity of their own home, as well as of local and high-level networks (with labour costs the biggest fraction of total cost, rather than the cost of components).
Next Jonathan took us through the model they are developing to estimate the network upgrade requirements for installing large numbers of heat pumps. The model combines housing and network data to find the nearest substation for each property in the area of interest. Substation capacity requirements are then calculated for a range of deployment rates. As an example, they found that a substation in an urban area near Glasgow with high amounts of flats and social housing could need 14% more capacity in a scenario with 20% uptake. However, this rose to 21% in a scenario where social housing was prioritised (to help avoid unfair network charges). Meanwhile a suburban substation could need 67% more capacity with 20% uptake (with larger properties), rising to 300% more capacity with 100% uptake.
Off-gas grid properties are expected to decarbonise faster as heat pumps are the only viable long term option, whereas hydrogen in the gas network could decarbonise on-gas properties in the 2030s. In addition, demand is higher, and existing oil and LPG-based heating has high emissions. However, a rural off-gas community may have to upgrade the same asset to the next available capacity several times to reach 100% deployment under the current “minimum viable scheme” rules meant to minimise bills. Hence Jonathan outlined that they are looking at Local Area Energy Plans that could allow the whole upgrade to occur in a single step, reducing overall costs. Finally, Jonathan showed a map with some early modelling they have generated for the town of Dumfries (Figure 1) quantifying additional peak electricity demand. This indicated 68.7 MW total additional peak demand for Dumfries caused by 100% heat pump uptake.
Jonathan then took us through a number of policy implications arising from their results. He said Ofgem are currently undertaking a Significant Code Review on Access and Forward Looking Charges, including domestic connection charging. On the one hand, minimising connection charges will help accelerate uptake to meet deployment targets. This could be achieved by shifting the charging boundary downwards (so homeowners only pay for upgrades on their street). But this would have the effect of increasing Use of System (UoS) charges and in turn increasing electricity bills. Vulnerable consumers need protection from this. Connection charges can also vary significantly by region; these could be capped at a standard rate so that everyone pays the same no matter where they live. Another option is to socialise network costs through taxation rather than bills. This could be general taxation, or focussed on emitting sectors e.g. using road tax to pay for network upgrades needed for EV charging.
During a lively discussion, Jonathan and Stuart outlined some of their ideas for extending their work. Currently their model uses estimated data about demand diversity (where not everyone uses maximum demand at the same time) to reduce peak capacity requirements, but data from larger real world trials is needed to improve understanding of this effect. Greater understanding is also needed about demand clustering e.g. where homeowners thinks it is prudent to top up their EV during cold spells, exacerbating demand. They also intend to consider thermal storage and hybrid heat pumps, which can help in cold weather when full heat pumps are less efficient. Smart systems (such as demand response, or preheating) could also help reduce capacity requirements, although Ofgem’s concern for safety means this must not come at the expense of reliability.
What did I personally take away from this fascinating dig into some of the detail around decarbonising heat? Well, I learnt how existing regulations (RIIO, charging mechanisms, upgrade limits etc.), which help protect consumers during normal times, may need changing to enable rather than hinder a one-off transition like heat decarbonisation. Care is also needed to allocate costs fairly across geographical regions and demographic groups. I also learned how intermediate decarbonisation targets, whilst intended to prevent delayed action, could end up forcing deployment of existing technologies like heat pumps, preventing the later uptake of future technologies like hydrogen, an insight that is particularly relevant to me in my CREDS work modelling heat decarbonisation pathways. Stuart and Jonathan’s work has thrown up some important insights so far, and it will be interesting to hear about what else they find.
[i] National Statistics (2018). Estimates of Households and Dwellings in Scotland, pdf (53 pages, 3.3 MB. Opens in a new tab), National Records of Scotland.
[ii] Department for Transport (2020). Government takes historic step towards net-zero with end of sale of new petrol and diesel cars by 2030 (opens in a new tab).
[iii] Scamman, D., Solano-Rodríguez, B., Pye, S., Chiu, L. F., Smith, A. Z. P., Gallo Cassarino, T., Barrett, M., Lowe, R. (2020). Heat decarbonisation modelling approaches in the UK: An energy system architecture Perspective. Energies, 13(8): 1869. doi: 10.3390/en13081869
[iv] Note the numbers included throughout this blog should be taken as indicative estimates.
Banner photo credit: Donald Edgar on Unsplash