Appendix 1 Heat and work from energy sources and in energy services
Energy services can be divided into two categories: firstly those that are essentially delivered by heating (raising the temperature of something), and secondly those that are delivered by some other form of energy (e.g. electrical or mechanical work).
In buildings, raising the temperature of the building, heating water and the variety of different forms of cooking are all forms of heating services. In industry, there are a large number of processes that depend on heating to a wide range of different temperatures. In contrast, in transport there are few heating-related services. Services in industry and buildings that are traditionally only provided by electricity tend to be work-related, notably the provision of motive power through electric motors, but also increasingly information services. In transport, the service itself can only be provided by work, but has typically relied more on local conversion of fuels in internal combustion engines.
There are some services which are a little more complex to categorise. Space cooling is, in principle, a heating service, but it predominantly supplied by refrigeration systems driven by electric motors. For the purposes of this analysis, it is therefore classified as a work-related service. Similarly, the heat required for hot water in washing machines and dishwashers is predominantly supplied by electricity. The analysis also treats lighting as a work-related service. The oldest lighting technologies, candles and oil lamps, used combustion, but modern lighting devices require electrical work, either to achieve the high temperatures needed for incandescence in the visible spectrum or in modern devices, such as light-emitting diodes (LED) and fluorescent lamps, to convert electricity selectively into photons in the visible spectrum.
Some industrial processes are also complex to categorise within this simple heat/work binary division. Notably, electrochemical reactions, by definition, require work in the form of electricity, but may also require heat, for example in the Hall-Héroult process for primary aluminium manufacturing. We classify these as work related, due to the essential role of electricity. In some other electricity using processes, notably electric arc steelmaking, electricity is a heat-producing fuel. In other cases, such as petrochemical and ammonia production and primary steel-making, fossil fuels provide a chemical reagent as well as heat. In this paper, they are categorised as requiring heat, and the accounting process set out in Appendix 4 below requires the replacement of fossil fuels by some other combustion fuel.
For the purposes of this paper, we also make a binary division of energy sources into those that provide work and those that provide heat. In the current global energy system, fossil fuels are the dominant producers of heat. Biomass also provides heat via combustion and geothermal energy exists as a heat source. In addition, the energy from nuclear fission, although originating as high energy particles and photons, has only ever been captured as heat. Where these energy sources are required to provide work, this has been done through heat engines of various kinds. In some cases, it has proved an efficient option to use these fuels for combined heat and power (CHP), i.e. to use heat rejected from the heat engine to provide heating services.
Most other forms of renewables produce only work, usually in the form of mechanical work. These include power from wind turbines, hydro-dams, waves and tidal energy.
Solar energy can be used to provide work or heat. Examples of the latter include ‘passive solar gain’ for space heating, ‘active solar heating’ of water and ‘concentrating solar power’ for electricity generation using heat engines. However, the rapid growth in solar energy has been driven by the use of photovoltaics, which convert solar energy directly into electrical work (the inverse process of LED lighting). For the purposes of this paper, we therefore treat solar energy as a source of work.
Appendix 2 Energy efficiency and its metrics
The term energy efficiency does not have a universally agreed definition. Like any form of efficiency, it can be conceptualised as the ratio of a ‘useful output’ to a ‘total input’, but these terms are not defined or used consistently.
The broadest and commonest definition of ‘useful output’ is the energy service delivered. This enables incorporation of all the technical and social changes that might be utilised to improve the efficiency of energy service delivery, including for example modal switch in transport, materials utilisation efficiency in industrial production, and insulation of buildings to reduce heat loss or gain. However, energy services are frequently difficult to measure and, in some cases, even to define. For some important energy services, such as thermal comfort and mobility, the appropriate metrics are not specified in terms of energy units, and therefore the metric of the efficiency of their delivery (e.g. passenger km per Joule for mobility) are service specific. This prevents meaningful aggregation across different service categories.
In the context of this paper, the definition of energy efficiency is more straightforward, as the types of efficiency improvement considered are confined explicitly to the efficiency of conversion devices for different forms of final energy use, for example the substitution of boilers by heat pumps and internal combustion engines by electric motors. These devices have better-defined inputs and outputs, both measured in energy units. In essence, the output metric of energy service in broader definition of energy efficiency is replaced with ‘useful energy output’. The measure of efficiency is therefore the ratio of useful energy output to final energy input, a dimensionless ratio, normally quoted as a percentage.
There are limits to achievable efficiencies as a result of the second law of thermodynamics. Indeed, the key findings of this paper—that work may generally be converted to heat more efficiently than heat may be converted to work—result largely from that law. In some cases, for example in heat pumps and refrigerators, this enables work to be used at efficiencies of greater than 100%, as the work is used to pump heat, to or from ambient, and the conventional definition of ‘energy input’ excludes ambient heat and coolth.
So, whilst both heat and work are measured in energy units, they are not generally of equal value. An alternative framing that addresses this inequality is exergy analysis (Moran & Sciubba, 1994), where exergy is a measure of the ability of an energy source to do work. Exergy therefore has a numerically equal value to that for energy when work is measured, but a smaller numerical value for energy as heat, with the degree of ‘down-rating’ dependent on temperature. Various authors have preferred exergy analysis when investigating the scope for technology improvement within current energy systems (Hammond & Stapleton, 2001). In exergy analysis, heat engines, e.g. turbines and internal combustion engines, have theoretical maximum efficiencies of 100%, compared to a much lower value in energy analysis. And the maximum efficiency of a heat pump cannot exceed 100%.
Exergy analysis is well-established in thermodynamics and has a long history ecological economics (Georgescu-Roegen, 1993). However, it is scarcely used in energy economics and policy. Almost all global and national data sources, models and policy analyses are constructed in terms of energy, not exergy. In this paper, we use energy analysis, primarily for that reason. It would be possible to reconstruct the analysis in exergy terms. The numerical values in the results would be different. Energy sourced from heat would have lower relative numerical values than that sourced from work, and the energy services requiring heat would have lower relative numerical values than those requiring work. The shift in the global energy economy described in this paper, from heat-producing energy sources to work-producing energy sources, would appear partly as a change in these relative values, rather than increased conversion efficiencies. But the reality represented would, of course, be the same. The key conclusion of the paper would be still be that the final energy needed to provide the same energy services is lower from a work-based system than a heat-based system.
Appendix 3 Current global energy use assumptions
Assumptions about current energy use in industry are shown in Table 2.
Total industrial energy use is taken from Low Energy Demand scenario for 2020 by Grübler et al. (2018). The split across between different major industrial sectors is taken from Fig. 2 of Cullen and Allwood (2010).
Reliable data for the splits by process type and fuel within each industrial sub-sector are not available at the global level. To estimate these for this paper, we have used UK data (ECUK, 2020) as the default. This implicitly assume that global practice within each sector is similar, which is a reasonable assumption in most cases. Where UK data does not conform to the sectoral split in Table 2, we have made supplementary assumptions as follows. UK data does not distinguish between steel and non-ferrous metals. We assume that the aluminium industry uses 40% of the electricity and 10% of the other fuels of the total metals sector, based on Energy Information Administration data (EIA, 2014). Within the steel industry, the fuel split is 79% fuels and 21% electricity, based on the work of He and Wang (2017). UK data on paper is aggregated with printing and publishing and therefore not representative of the global paper industry. The paper industry split between drying and separation and other low-temperature process therefore uses data on paper mills and pulp mills from Lawrence et al. (2019).
Petrochemicals account for about 12% of global oil use (IEA, 2018b), and therefore about 4% of global primary energy use. In this analysis, it is implicitly assumed that oil used as a feedstock may be substituted in the same way as oil used for energy in the chemical sector. This is a significant simplification, but not a major uncertainty in the context of the whole analysis.
Total energy demand in buildings in 2020 and the shares of fossil fuels, electricity and traditional biomass are taken from the same Low Energy Demand scenario (Grübler et al., 2018). In order to estimate the energy use in different process types, total demand is first split into separate contributions from residential and non-residential, assuming the former is 74.3% (Lucon et al., 2014). These are then each split into the different end use processes using the shares shown in Table 3 (Lucon et al., 2014).
The end use fuel is assumed to be 100% electricity for lighting, cooling and appliances. Electricity use in cooking is assumed to be 3% of total building demand, with the remainder of cooking energy use from traditional biomass. The remaining traditional biomass demand is assumed to provide space heating. The shares of electricity for space heating and water heating are assumed to be 5% and 15% of the total for each end use. This ensures that the total share of electricity in the sector as a whole corresponds to the overall fuel mix assumed.
Data on transport energy use by mode and fuel type are taken from the Supplementary Information of Khalili et al. (2019) and set out in Table 4.
End use demands smaller than 0.1EJ/year have been neglected. End use devices are assumed to be internal combustion engines for fuel and electric motors for electricity. Total energy use is consistent with the same Low Energy Demand scenario (Grübler et al., 2018) as the other sectors.
Appendix 4 Future energy conversion assumptions
This section sets out the methodology used to calculate future final energy demands. Current energy demands by process type and fuel (see Table 1 and Appendix 3) are the starting point. For simplicity and transparency, it is assumed that there are no changes in energy services demands and no changes to energy efficiency other than in conversion processes from final energy to useful energy.
All end uses are supplied by either electricity or hydrogen. Electricity is assumed to be the preferred zero carbon end use fuel in most applications. Hydrogen is used for those demands judged from the existing literature to be difficult to electrify. These include industrial processes, heavy vehicles, shipping and aviation, and some space heating.
Detailed assumptions are set out below in Table 5. This documents the conversion factors used for each combination of sector and process type (e.g. ‘industry, high temperature process’). Table 5 is essentially a set of 2 × 2 matrices that document the conversion factors used to calculate post-transition energy demands, split into fuel and electricity, from the pre-transition fuel mix. As an example, the quantity of (non-electric) fuels used in industrial high-temperature processes falls to 67% of its pre-transition level, 13% of pre-transition direct fossil fuel appears as electricity post-transition and the remaining 20% is the final energy efficiency gain. For the same set of processes, all the energy currently provided by electricity is unaffected.
‘Pre-transition fuels’ are predominantly fossil fuels; ‘post-transition fuels’ are assumed to be hydrogen. For the buildings sector, an additional current fuel type is considered: traditional biomass. But there is no traditional biomass in the final fuel mix, and therefore the conversion matrices are 3 × 2 for this sector.
In industry, it is assumed that changes in high-temperature process conversion efficiency are dominated by those in the steel sector. Currently electric arc furnaces produce only 25% of steel globally, but this is very variable across countries ranging from 50% in most OECD countries to only 10% in China (He & Wang, 2017). Electric arc furnaces use only 40% of the final energy of the blast furnace process route. We assume that the global industry shifts to the current process mix of the OECD. Production of iron by hydrogen direct reduction has a similar energy consumption to blast furnace production (Vogl et al., 2018).
Low-temperature processes in industry are very largely dependent on steam. Process change as a direct outcome of the energy transition is therefore unlikely (although the changing costs of different fuels may lead to innovation). The change envisaged here is therefore a shift from fossil fuel to electric boilers with a 20% conversion efficiency improvement.
Drying and separation processes at temperature below 120 °C are amenable to conversion to heat pumps using existing technology. It is assumed that 80% efficient boilers and 100% efficient electrical technologies are replaced with heat pumps with a coefficient of performance of 240% (Arpagaus et al., 2018).
It is assumed that space heating changes are achieved consistent with those in the buildings sector set out below. Changes in other end uses are assumed to reflect those in low-temperature process to ensure a conservative assessment of potential.
In buildings, space heating is the largest energy user in cool and temperate climates. From an efficiency perspective, the ideal solution is to use high-efficiency heat pumps. However, there are concerns that 100% substitution may not be economic due to the very large peak in winter electricity demand it could cause (Eyre & Baruah, 2015). We therefore assume that some hydrogen contribution will be needed. We assume that existing fuels are replaced by 90% electricity and 10% hydrogen. We assume a long term achievable efficiency of 310% based on air source heat pump data from the cold climate of northern China (Zhang et al., 2017), replacing fossil fuel boilers with an 80% efficiency and 100% efficient electric resistance heating. For hydrogen use, we assume an efficiency based on a gas-fired heat pump (Critoph et al., 2020). Where traditional biomass is replaced, we assume 80% efficient (for space heating) traditional biomass stoves (Geller, 1982) are replaced with air source heat pumps.
For water heating in buildings, it is assumed that direct use of fossil fuels, electric resistance heating and traditional biomass are entirely replaced by electric heat pumps with an efficiency of 220%, which is the median value of a recent field study (Willem et al., 2017). Where the current fuel is traditional biomass, it is assumed to be used with an efficiency of 14% (for water heating) based on Geller (1982).
The paper assumes that cooking is completely electrified and that this efficiency is 80%, which is characteristic of a modern electric hob (Hager & Morawicki, 2013). Traditional biomass displaced is assumed to be used with an efficiency of 6% for cooking (Geller, 1982).
Lighting, cooling and appliances are already completely electrified. Further efficiency improvements can be expected, but none is assumed here to be the result of the transition.
In transport, it is assumed that electrification occurs in all modes to a greater of lesser extent. The likely penetration of electricity and the emission factors for different vehicle types are taken from a recent comprehensive review (Khalili et al., 2019).
It assumed that light vehicles (cars and vans) are completely electrified. Internal combustion engine vehicles ICE) with a fuel consumption of 0.782 kWh/km are replaced with battery electric vehicles (BEV) with a fuel consumption of 0.182 kWh/km.
For heavy vehicles it is assumed that only 50% of total vehicle distance travelled can be electrified, with the remaining 50% supplied from hydrogen fuel cell electric vehicles (FCEV). Fuel consumption data assumed are for ICE 3.51 kWh/km, for BEV 1.87 kWh/km, and for FCEV 2.11 kWh/km.
Bus fleets are assumed to be 80% electrified, with only long distance buses powered by hydrogen fuel cells. Fuel consumption data assumed are for ICE 4.09 kWh/km, for BEV 1.87 kWh/km, and for FCEV 3.12 kWh/km.
Rail transport is currently the most electrified transport mode. We assume that the transition will stimulate a continuation of this trend through to full electrification. Specific energy consumption for rail freight engines is 0.04 kWh/tkm for electricity compared to 0.1 kWh/tkm for diesel engines. For passenger railways, the equivalent figures assumed are 0.09 kWh/pkm for electric trains and 0.2 kWh/pkm for diesel.
Aviation is generally assumed to be difficult to electrify, because of the weight of batteries and high power requirements. However, recent work shows that journeys of less than 2000 km might reasonably be electrified (Schafer et al., 2019). In this paper, we assume electrification of 33% of total air travel with the remaining 67% converted to hydrogen. Using data on passenger aircraft, the fuel consumption data assumed are 0.54 kWh/pkm for conventional planes, 0.2 kWh/pkm for electric planes and 0.39 kWh/pkm for hydrogen.
Marine transport remains an important mode for freight. It is widely seen as a difficult mode to electrify with more attention focussing on hydrogen and ammonia as zero carbon options. Here, we assume that electrification is limited to 10% in short distance trips such as ferries. Using data on marine freight, the fuel consumption assumptions are 0.042 kWh/tkm for ICEs, 0.019 kWh/tkm for electric ships and 0.039 kWh/tkm for hydrogen-powered ships.