originally posted 21 April 2016
The ideas set out on this page were developed, and are to be published shortly, as part of a longer paper commissioned by the Energy Technologies Institute (ETI). They are intended to identify some of the policy, regulatory and practical questions associated with what are emerging as prima facie good technology strategies for the UK heat sector. The author acknowledges the support and encouragement provided by the ETI.

Collective or individual solutions?
It is useful to distinguish options that depend on essentially collective decisions, for heat networks, and those that continue to be based on individual choice. The probable outcome may be a combination, but they raise very different practical and policy questions.

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.

Scale of the heat load and interaction with the power sector.
The scale of the heat sector matters and conditions any strategic approach.  Decarbonisation of the heat sector is widely assumed to require a very substantial ability to use electricity as an important element in substituting for the direct consumption of fossil fuels such as gas. This is a challenge because meeting existing UK heat loads from electricity generation alone would require a very large expansion, even up to a doubling, of current kWh generation, and, given the seasonal and temperature dependent nature of UK heat loads, a proportionately larger expansion of capacity.  Thermal demands of domestic and public/ commercial buildings are estimated in a 2012 CCC report[1] at about 450 TWh pa; this compares to current total electricity consumption of about 300 TWh pa. 

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[2] 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%[3]. 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.

The Collective Solution. Local Heat Networks.
Heat networks, for distribution of heat in order to warm buildings, are often associated with options for combined heat power (CHP) operation, but historically and internationally they have also been associated with other formats, eg conventional boilers fired by oil, coal or gas[4]. In principle future development could be in association with, for example, biomass or fossil fuel input with CCS, biomass without power generation, use of hydrogen fuel, dual firing, geothermal sources, or possibly as part of wider large scale heat storage.

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.

Compulsion or choice with heat networks
If we assume near universal participation as a necessary condition for the viability of most heat networks, then we have to confront the problem that many consumers will be reluctant to incur the disruption or other “transaction costs” of joining a heat network. These are in many ways akin to the problems of implementing programmes for raising insulation to a high level across the housing stock as a whole.
Insulation of buildings and energy efficiency is usually assumed in longer term projections. The benefit is clear – lower aggregate heat and electricity requirements, and lower capital outlay and running costs. The negatives are issues relating to the retro-fitting of the existing building stock, chosen policy instruments, and transaction and disruption costs to consumers.  Increasing take-up may be achieved by simple economic incentives and subsidies but administrative measures, amounting to a degree of compulsion, have also been proposed by some commentators.
There is therefore a case for finding ways to link the two initiatives in the public perception, not least to reduce the element of discrimination that might be felt in areas where a heat network was being imposed.
Compulsion in a formal sense is unattractive, although comparable historical examples might be cited, such as the imposition of smokeless fuel requirements to combat city pollution in the 1950s. In practice some combination of “carrot and stick” is likely. This might for example be a selection from or combination of the following:
  • 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.

Operations of CHP schemes and interaction with power systems

Issues in CHP operations reflect the fact that there is normally a trade-off between heat production, expressed as the temperature of output heat, and the thermal efficiency of electricity generation.  One question is therefore whether CHP could or should be wholly subject to central dispatch, thus enabling the SO to call for extra power at times when the system is under stress and additional capacity is required. This is a potentially complex question. First it further complicates an already difficult task for the SO.  Second it creates difficult conflicts of interest and duty within the CHP scheme, ie whether its primary responsibility is to heat customers or to the national power supply, or to meet a financial target. Third, reducing heat output in severe winter weather, in order to increase electricity output, could induce compensating use of direct electric heating appliances by individual households, defeating the purpose or even producing an adverse system feedback.
In theory there might be a case for comprehensive optimisation by a central overall system operator, but the problems of possible multiple objectives and excessive centralisation are much more apparent than the benefits. It should be clear that the primary duty attaching to CHP schemes is to provide a secure supply of local heat.
This does not need to inhibit purpose specific contracts between the CHP facility and the SO. The operator of the heat network would deal directly with the SO and the CPA, and the basis for kWh sales would be some combination of negotiated contract and tariff terms, analogous to those for retail suppliers of power. Contract terms would need to reflect technical constraints on the CHP plant, the priority attaching to heat output in winter, and CHP design should aim to maintain flexibility in operations.

 Organisation and strategy for heat networks.
The heat network sub-sector is potentially diverse. It could include for example new schemes for isolated but concentrated rural communities with relatively small scale heat needs, conversions of established medium scale apartment blocks with communal heating, and larger and more controversial city wide schemes, including small scale nuclear generation. It is city schemes that are probably the most relevant to achievement of low carbon heat penetration in the ETI scenarios. A critically important factor is that of network economies of scale.  Many schemes may only make economic sense with a sufficiently large number of dwellings at a fairly high density, possibly and controversially combined with near-universal participation.

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.
Non-network Heat Sector. Consumer Choices and System Constraints.

Even in the longer term, heat networks will still leave a very substantial part of the population dependent on individual heating choices. For these consumers the main low carbon choices are the following.
Heat pumps can in principle reduce electricity requirements by multiplying the kWh of electrical input to produce up to 3.5 times the kWh of heat output. One drawback is that, for air source heat pumps, theoretical coefficients of performance (COP) of 3.5 can deteriorate badly in cold weather.  This further lowers load factor and does little to resolve system peak load problems. A related issue is that heat pumps in low density environments may be a high percentage of local load and hence pose reinforcement or load balancing problems for local networks.
Household costs, if tariffs reflect both peak load pricing for the system as a whole, and local network reinforcement costs, are also a potential issue.  Household specific installation costs are also likely to be substantial, since they include the heat pumps themselves, and are  possibly higher than those for heat networks. Nevertheless they are still likely to have a comparative advantage for areas of lower population density, even if this may also be where network reinforcement problems are most acute. An attractive feature is that their installation and operation represents individual consumer choices rather than collective decisions and responsibilities.
Direct resistive electric heating, for use in household storage radiators, is a well established but niche market. Even though it accounts for a small percentage of total heat, it is already a significant contributor to winter night electricity load. As a relatively easy and low cost solution to improving the daily load factor in winter it has a potentially useful role in most scenarios, subject only to the qualifications and limitations above. However once the existing “load troughs” have been filled, the incremental cost of supplying heat through this route will necessarily start to reflect additional capital costs. “Full cost” electricity is an expensive form of heating. Policies and practices on consumer tariffs, and in particular any “promises” made to existing and early adopters of storage heating, will be an issue.

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

Seasonal heat storage.  Implicit in much of the above discussion is the high value that attaches to effective forms of seasonal heat storage. Some scenarios include hydrogen and its possible injection into the gas network or conversion to gas or liquid fuel, but the dependence on primary electricity or CCS may make these relatively expensive options, other than for peak or back-up.  Low cost seasonal storage of heat per se, rather than energy, would be a very welcome option for reducing capital costs. It is sometimes referenced in the context of ultra-low energy or “passive” houses, but there is little evidence as yet that it could be a significant element in retro-fitting for the UK housing stock.
Much of conventional analysis is therefore posited on the assumption that it will not play a major role in our timescales. It has not therefore been covered here in any depth but clearly deserves further examination for the longer term; it has the potential to alleviate or remove a number of the operational and cost/ low load factor problems discussed. As such it is also a potential “game changer”, a disruptive technology option posing a risk to other investments under consideration in the heat and power sub-sectors.
Roll-out of heat network development in tandem with programmes to improve energy efficiency of the building stock. There are a number of common issues, identified above, that suggest possible advantages in linking these developments. This provides one argument for considering the option of a broader Heat Authority to promote a balanced overall development of the sector.

Energy pricing and the rebound effect. There is an extensive literature on the rebound effect, essentially analysing the phenomenon in which a varying but sometimes high proportion of efficiency gains is used to support higher consumption. Given the scale of what a low carbon heat sector requires of the power sector, this is a potentially major issue. The main policy instrument to counter rebound is to ensure that the generally higher cost of low carbon heating through electric methods is reflected in higher prices. The proportion of household income spent on heating is much more likely to be stable.[5]
It follows that the implementation of policy for the heat sector would benefit in the transitional phases from higher levels of carbon prices, and in the longer run from ensuring fully cost reflective pricing. The second point is particularly relevant in the context of pricing back-up or peak load supplies and possibly in relation to local network balancing.

A rising marginal cost curve, windfall gains, and equity between consumers. The analysis above has identified a number of situations in which there are potential sources of low cost heat but in which these are all supply limited. These include geothermal energy (geographically limited), biomass for local CHP schemes (probably supply limited), and the initial infill of the winter load curve for storage heating. There will be some interesting regulatory questions, to which there is not necessarily a consistent and uniform answer, as to how this should be reflected in passing costs through to consumers. 
Role of a heat authority.

The main purpose of a National Heat Authority (NHA) would be to act as a stimulus to the development of large heat networks, although it might be considered appropriate for it to have a slightly wider advisory role in relation to the heat sector as a whole. It would not have any significant commercial or operational responsibilities on a day-to-day basis. Its functions would be essentially strategic and advisory, in identifying suitable models from overseas experience, identifying most promising UK locations – primarily city-scale with the most favourable geographies. This could extend to a role in setting standards of good practice, and possibly in building links with the financial community.
The NHA could sit within government or could be an arms length body. In order to avoid duplication and reduce costs, it would be worth looking at existing bodies deemed to have general expertise in heating buildings, such as existing CHP bodies, trade associations and the Carbon Trust, to see what functions could be assumed by, delegated to or absorbed within those bodies.

[1] Decarbonising heat in buildings: 2030–2050. Committee on Climate Change. April 2012.
[2] Heating degree days are the number of degrees by which average temperature falls below a “base”, eg 15.5o C, summed over all days for a given period.  A similar measure, cooling degree days, can be applied
[3] Degree day statistics are readily available in official UK weather statistics .
[4] The widespread adoption of domestic gas condensing boilers has dramatically improved the efficiency of domestic gas heating, to a significant extent weakening the efficiency arguments for CHP.
[5] Some energy economists have made a much more general observation of a similar nature, namely the remarkable similarity in energy expenditure as a percentage of GDP, as between countries with higher and lower energy prices.

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