Relevant options for low carbon development of the heat sector are conditioned by the nature of the existing housing stock, but also largely by geographical factors. For heat networks, or “district heating”, these factors include proximity, for a relatively small proportion of buildings, to geothermal heat sources, population densities, questions of what constitutes sufficient scale to deploy heat networks economically, and, under some scenarios, proximity to gas or CCS networks. Heat networks, in which heat is distributed from a common source, raise a number of diverse practical questions, but will tend to operate at local authority or city levels rather than as units within a connected network.
A large percentage of households will also continue to make their own choices of heating system, independent of local heat networks, and their most important low carbon options are likely to be heat storage and electric heat pumps. These have important, but very different, implications for the power sector, both at the level of balancing generation and load at aggregated levels, and for providing adequate capacity within local distribution networks.
A strategy for the heat sector therefore has to cover two heat delivery models which raise very different regulatory and practical challenges, in one case a “collective” solution typically initiated at a municipal level, and in the other case solutions mainly chosen and installed by individual consumers, but which pose wider coordination and network problems of a different kind.
The same CCC report indicates future heat loads, taking into account UK population growth, of over 400 TWh pa in the period from 2030 to 2050, even on the assumption of high efficiency achievement. More modest assumptions on efficiency require much higher amounts, of up to 550 TWh by 2050. Ambitious energy efficiency rollout projections are therefore a very important part of strategy, but the scope for reducing UK buildings’ thermal demands will ultimately be limited, leaving a remaining heat supply requirement that is still very large. Such a change in scale of kWh supply is likely, a priori, to have very significant implications for local power distribution networks as well as for meeting aggregate demands.
Even if some of the heat need can be met through non-electric routes such as geothermal heat or biomass, and notwithstanding the useful energy gain from heat pumps, the interplay with the power sector is substantial, with the possibility that heat choices, collective or individual, could be a dominant factor in the design of a suitable mix of plant types for power systems and for their operation.
There is a potentially high cost of providing heat either through on premises electric heating methods, or through district heating networks, compared to “on premises” gas boilers. Although costs might be lower in favourable conditions, eg for heat networks in high density locations, or for further exploitation of current troughs in conventional electric load curves, low cost options are likely to be location constrained or supply limited. The high cost per kWh of heat energy is mainly due to the capital cost of additional generation capacity and/or new heat networks. This factor is accentuated by the strongly seasonal and temperature dependent nature of heating requirements, and further fuelled by the risk (for renewables) of low output at the seasonal peak. For electricity, these factors require an increase in kW capacity even larger than in kWh energy production, in order to meet heat loads.
A simple analysis of monthly long term averages for recorded degree days suggests that even if within day and within month heat storage were adequate to spread consumption evenly over days and months, heat load factors would still only reach about 54%. This is before taking into account the need for significant margins to cover severe cold spell conditions, or imbalances within the day or the week. A 54% figure reflects a possibly optimistic assumption that short term variations in heat load can be quite easily accommodated.
A poor load factor matters a lot due to the impact on unit costs of capital intensive low carbon electricity generation. Electricity generation facilities (hypothetically) dedicated to providing the main or only means to heat provision would be likely to operate at most at 50% load factor, even for non-intermittent options. There is substantial scope for “in filling” of existing electricity load profiles through, for example, the established heating option of night storage radiators. But, although this is a potentially valuable contribution, it is ultimately limited; and other applications, such as electric vehicle re-charging, may be in competition for some of this “space” in the daily load pattern. It does not in any case deal with the seasonality factor. Poor load factor substantially increases the contribution of electricity capital costs, the dominating element in low carbon systems, to average kWh costs associated with meeting heat demand.
Reflecting the above considerations, some alternative low carbon or electric options for the heat sector are set out below, leading on to consideration of network, commercial and regulatory issues. All pose some specific challenges for regulation and for a coordinated approach to heat and to the energy system more widely.
We should note the general point, rapidly emerging as an important factor post Paris, that any large scale direct use of biomass within large systems is likely in the medium term to be within schemes based on bio-energy with carbon capture and storage (BECCS). This is because ambitious global targets are now for “net zero” emissions, implying that some means will be needed to extract CO2 from the atmosphere. The only viable method currently in sight is via enhancement of the natural carbon cycle followed by lock-in of the additional CO2 using CCS, in other words BECCS.
Non-electric low carbon options include geothermal energy, where lower cost options are likely to be geography specific. A second is use of conventional fossil fuels but with CCS. This in turn may be limited initially to sites adjacent to a relatively small and undeveloped CO2 gathering network, and carries the burden of the higher capital costs associated with CCS. A third is use of biomass or waste, with CCS, for firing district heating boilers.
The electricity linked solution for local heat networks is some form of combined heat and power production (CHP), with distribution of hot water as the heat vector. In this instance the source of the heat energy is thermal power generation plant. It is low carbon only for nuclear or for fossil plant with CCS.
A general feature of district heat distribution is the large volume and large mass of water at relatively low temperatures, the last accentuated for CHP. This implies high capital and operating costs of distribution. In most circumstances, the most cost effective means of transporting and delivering energy over significant distances are likely to be electricity by wire, gas by pipe, or through a hydrocarbon store as a liquid fuel, rather than as low grade heat, with a low energy density, distributed through pipes to carry hot water. This factor is accentuated when the gas or electricity network is already in place or will be required anyway.
So the likely development of heat networks will be as local entities, without the development of national or large scale bulk transmission of heat. This strongly conditions approaches to developing and regulating heat networks. All district heating schemes will face the challenge of local capital costs in heat distribution and connection costs for individual households. A main problem is the cost and other issues associated with building new networks to distribute the heat.
The hard questions derive from the very obvious economies of scale in setting up a district heating network, and the alternative choices that consumers may want to make, if they have a free choice of heating method. Universal or near-universal participation may well be essential to the economics of many or most schemes. This is not necessarily a problem for “new build” situations. The equivalent of district heating schemes exist on a small scale, for example, in many large London apartment blocks, with an attendant lack of choice for residents. Typically they pay a fixed charge and their heat consumption is not metered (although this is changing). But residents in this case have “chosen” this form of heating when they moved in.
Implementing larger schemes that involve major retro-fitting is much more problematic, and, in addition to technical and engineering considerations, depends either on an element of compulsion or on making the district heat option significantly more attractive than alternatives in terms of household heating costs, a matter whose economic and political ramifications need to be considered in setting out a strategy for the heat sector.
- Consumers are put on notice that existing services, eg unrestricted mains gas supply, will not be available after a certain date, or only available at a substantially higher price.
- A direct subsidy towards the capital cost of retro-fitting to the consumer’s own premises.
- Partial funding of the heat network through local taxes, so that householders recognise they are already paying part of the cost anyway.
- A guarantee that total future running costs will not exceed those of some benchmark calculation for the alternatives available to the consumer, eg electric storage heating.
- Ensuring that running costs for the alternatives fully reflect cost, including back-up energy per se. This would at least reduce the subsidies or the degree of compulsion necessary to induce near universal participation. Carbon pricing may be one element in this.
- Incentives through energy rating of buildings which might improve their value in selling, or be reflected in local property taxes.
In strategic terms, the intuitively obvious approach is to start with the “low hanging fruit”, where costs are lowest, and where consumers are less likely to be resistant to a potentially disruptive change. This increases the chance for early success and provides an opportunity to learn from the technical and other obstacles encountered in the first projects, before proceeding to more challenging schemes. After the more obvious “new build” opportunities, the next category would perhaps be areas with high density of dwellings and a high proportion of rented property, where a primary responsibility rests with landlords, public or private. This reflects an assumption, possibly misplaced, that owner occupiers will object more strongly to the disruptions associated with retro-fitting heat networks.
Many of the factors identified above, but especially consumer resistance, local disruption and “transactions costs”, may make investment in and operation of the heat sector quite unattractive to private investors, including existing power generators. Moreover the expertise and experience required to construct and operate large scale heat networks, which does not currently exist in the UK, is quite separate from that of power generation. The division is even more marked if heat networks are to be associated with small nuclear plants.
These factors mean it is improbable that heat networks will be “self- starters” in response to conventional market signals. Overseas experience suggests municipal involvement as one means of running and operating heat networks, but that does not prima facie correspond to UK historical approaches or to capacities in UK local government. The UK in any case has little recent experience of district heating and heat networks.
Many future energy scenarios and projections attach a significant future role to heat networks. However in either case we need to consider the question of what are the necessary conditions for heat networks to develop from a standing start. The general challenge to investment in infrastructure applies. There is not necessarily a need for a universal model but one plausible approach to large city-scale schemes might be the following:
- Establish a new “Heat Networks Authority” to identify the most promising candidate cities or other areas for early roll-out, to coordinate strategic planning with the power and other sectors, and to identify best practice from overseas experience.
- Government will almost certainly need to underwrite construction and other risks on early investments, but with the intention that these should rapidly become self-financing.
- The differences in culture and expertise requirements between generation (especially in the context of the small scale nuclear plant currently advocated in some quarters) and heat network maintenance are such as to suggest separate ownership. Small scale nuclear plant, to take just one of the possible options being floated, would probably be owned and operated by one or a very small number of specialist companies, whereas the heat networks would be local, separate, and possibly under municipal ownership. The two parts would be bound together by clearly defined contractual obligations.
- The sector is also generally compatible with private or public sector ownership and management of facilities, but private sector ownership would probably require quite strong contractual commitments or other safeguards to underwrite the long term nature of the investments.
- Local authority operation and financing of heat facilities is another option. An important practical consideration is the financial capacity of local authorities to borrow with a low cost of capital.
- The generation operator will be contractually bound to supply heat as its first priority, and will also have contracts with other entities in the power sector, and with the SO; electrical output may be varied up or down by agreement with the SO.
- Heat networks will operate as de facto local monopolies. For city wide heat networks there is a case for subjecting them to more formal and effective regulation, with OFGEM as perhaps the natural choice of regulator.
- Outside the large city schemes, there will be far more scope for local initiatives, and less obvious need for national support. All heat networks will have significant monopoly characteristics, as they already do within London apartment blocks. The latter have a degree of regulation, through ownership and resident associations, providing a basic but not necessarily ideal model; the legal foundations for smaller local schemes may need re-examination.
DASH. Resistive electric heating, for use on demand, is sometimes called direct acting space heating or DASH. Most households typically own some form of DASH, since its capital costs are negligible. Its occasional use is convenient but expensive (on a full rate tariff) and would most likely become even more so in any tariff system moving towards better reflection of the cost it imposes on the system. Even so it will continue to create peak problems if it is used as the fuel of last resort in cold weather or when the main household system is under pressure. It is therefore an important part of any analysis of the overall system problem.
Residual use of the gas network as a back-up or peak supply of heat to households or commercial consumers is certainly an important transitional option. Its longer term significance depends critically on overall emissions targets, and on whether conversion of primary electricity to hydrogen and its inclusion in mains gas supply becomes viable.
Issues different from those of heat networks arise for this less collective aspect of the heat sector. The biggest single issue may well be the potential rate of take-off for electricity based load, as heat pumps enter the steeper parts of the S-curve for market penetration. Given the potential scale of the load this could out-pace the growth in generation and in local network infrastructures. Likewise the “availability” of low price “off peak” electricity for storage radiators is probably less than 25 TWh and could also be exhausted quite quickly.
This may imply some quite sophisticated commercial and marketing calculations, on how to price the services associated with these forms of electric heating, and how to promote them to consumers. This would be primarily a responsibility of suppliers and depend on the volume of suitably shaped contracts secured from the CPA.
Marketing this type of heat also poses some awkward questions. There is a clear benefit to selling off-peak electricity from the current system load curve, at least if one assumes low carbon generation at night. However this may rapidly reach a supply limit, after which any incremental demands will face higher costs. Storage heater terms may therefore be on offer only for a limited period, but the customers will need to be assured of the continuation of their tariff for the life of their property.
Similar issues may arise in the local availability of both storage heating and power for heat pumps, to keep load within local network limits. These factors may imply some geographical differentiation in availability and in the terms on offer. The industry and the regulator will have to manage the fact of actual discrimination “by post code”. These questions will clearly be bound up with finding a rational approach to network pricing that moves beyond simple cost averaging, and sequencing will be of significant importance in encouraging the development of individual consumers moving towards electric solutions for heat requirements.
General Strategic and Policy Considerations