The vision of the future is clear: heating is going electric. The Intergovernmental Panel on Climate Change (IPCC) says as much, and the fall in average carbon factors below that of gas means it appears to make environmental sense. That’s that sorted. No more debates required; let’s roll out the heat pumps and brush up on our electrical engineering.
If only it was so straightforward. While electricity is getting cleaner, many complex issues need to be addressed before the industry switches to electric en masse.
The IPCC says heating systems will have to electrify, and states that if we wish to restrict global warming to below 1.5°C, rapid change is required over the next 10 years. The implication is that we need to decarbonise heat now, with technologies already to hand; there is no time to wait for hydrogen, although this may have a role later.
The National Infrastructure Committee (NIC) has investigated what electrifying heat might mean on a macro strategic level. Surprisingly, direct electric and heat pumps come out at broadly similar levels of costs. According to the NIC, the expense of retrofitting energy efficiency measures to allow the use of heat pumps offsets the reduction in grid-reinforcement costs required to run systems using direct electricity.
“Electrification of transport is on an upward trajectory and is competing with buildings for electrical resources”
But the main headline is that the costs of direct electric and heat pumps are high, with both requiring substantial investment in infrastructure and buildings. It is not surprising the IPCC concluded that ‘low carbon heating is among the toughest challenges facing climate policy.’
The National Grid has decarbonised faster than anticipated, but is facing local capacity restrictions arising from the rollout of decentralised energy technologies, which are already putting connection costs up.
Bear in mind also that the electrification of transport is on an upward trajectory and is competing with buildings for the same electrical resources.
Under the Kigali Agreement, traditional HFC refrigerants are being phased out, with limitations on alternative technologies available and, often, additional risks present in the replacement gases. This is naturally impacting on the heat pump market.
There are many pitfalls awaiting the unwary as these changes take place. As new F-Gas regulations prevent the use of refrigerant gases with a global warming potential (GWP) >2,500 post-2020, and drive up the cost of gases with high GWPs <2,500, heat pump technology is changing rapidly.
The HVAC industry is rapidly migrating to R32, but this can only be used in small or external systems because of its flammability. The refrigeration industry is migrating to low-GWP refrigerants such as CO2, hydrocarbons, hydrofluoroolefins (HFOs), HFO/hydrofluorocarbon (HFC) blends and ammonia, but these bring their own design and operational challenges.
This is not to say these systems are inherently unsafe, but that different and informed design approaches will be needed to manage the risk, with an ongoing requirement for good maintenance of refrigerant and refrigerant-safety systems.
It is easy to see a role for this technology in commercial buildings with a cooling load, but the situation becomes more complex in dense residential deployment. Large-scale heat pumps require novel low-temperature district heating distribution systems and specialised maintenance.
Similarly, if ambient loop heat pumps aren’t treated, maintained and run as a coherent system by a single landlord or operator, the risk of a systemic problem (for example, water quality), inadvertent tampering or alteration at an individual residence – leading to wider system issues – is high. Some heat loads may also be just too large to be met from heat pumps, given the available ground or roof area.
Some simple ‘low regrets’ options have been identified by the scientific community. A continued focus on energy efficiency is required in new and existing building stock. New-build must be designed, from the outset, to fit low carbon heating systems within the next 15 years. This will probably mean a continued focus on low-temperature water systems to allow future flexibility in heat supply.
Similarly, low carbon district heating systems in the right geographical locations are needed, but they are not a silver bullet for the wider challenge.
Whole-life cost is likely to be the key issue. The government’s electricity price forecast for the National Grid estimates a 12-25% rise in real prices over the next 10 years for residential, service and industrial users.
Any proponent of direct electric heating should bear this in mind when promoting these systems. Also, electrical infrastructure restraints in some parts of the country – such as the West and South West – are already having material impacts on project feasibility and capital cost
Electrical capacity – future risks
There is no doubt that some spare capacity exists in our distribution systems – for example, in London. But there needs to be careful consideration of how this is used, particularly with the rise of electric vehicles (EVs). Under current rules, a connection may be made to the electrical network for a given fee, provided capacity is available.
However, once significant reinforcement of the local power system is required, the connection or connections driving this pay a proportion of the costs of the local supply reinforcement. These costs can be large, potentially making development unviable – something that is already being seen in some parts of the country.
Furthermore, the balance of costs for reinforcement – that is, the costs not met by the connecting party – are met by the distribution network operator (DNO) and, ultimately, the consumer.
This continues to push up the price of electricity ahead of inflation, with the associated fuel poverty and economic impact of this. These costs may also be large. For example, if upon a new connection a 10MVA transformer needs replacing with a 15MVA unit to reinforce a system, the connecting party pays its share (the 5MVA uplift). However, existing consumers pay for the replacement of their equivalent capacity (the 10MVA).
This leads to a cliff-edge scenario, whereby connections for those who can get them are relatively cheap, up to the current system capacity. However, subsequent connections may be very expensive or have increasingly greater impacts on consumer electricity prices.
There is a risk that if we continue allowing development without strategic foresight, some new projects may absorb local electrical capacity, but once a critical level is met, connections for other electrically heated developments or transportation become too onerous in a given location.
This can affect not only large cities, but also rural towns and settlements where the electrical distribution system is weaker, and fewer alternatives to EVs exist for future personal transportation.
OFGEM and the DNOs are aware of these challenges, but there is a need for wider industry debate as to how these costs will be apportioned fairly in the future, particularly where the driver is new-build electrically heated development.
Therefore, it’s likely that the capital costs of connection and upgrading local electrical power networks to accommodate heating and transport, as well as traditional loads, will come to dominate future debate and decision-making on low carbon heating system selection.
Building owners, DNOs, operators and service engineers are likely to need to work very closely to understand these interactions, and particularly their long-term cost and maintenance implications.