[A condensed and sanitized version of this article has been published as a blog post on the Wood Heat Association website.]
Energy storage has recently become a hot topic. After 25 years of promoting low-carbon electricity generation technologies, the Establishment has decided to pay more attention to the mis-match between the production of that electricity and demand for electricity.
These tensions are exacerbated by the Establishment’s plans for heat. The two central planks of those plans are now:
- Biomethane injection into the gas grid
- Electrification of heat
As recently as 2013, the Establishment accepted that the potential of biogas was tightly constrained by the limited resource of suitable putrescible material. Falling gate fees at anaerobic digestion plants confirmed that constraint in real life.
But in the Government’s plans set out in the recent response to the consultation on reform of the Renewable Heat Incentive (RHI), the expected contribution from biogas was radically increased. They now expect biogas to supply over half of all the new renewable heat delivered by the RHI. This assumes some radical steps, such as:
- a 4000% increase in the rate of expansion of heat from sewage gas (presumably, without diverting that gas from CHP or electricity generation, which would be robbing Peter to pay Paul), and
- a fivefold increase in the amount of energy crops required for digestion.
A dramatic increase in the contribution from biomethane would require a matching increase in the UK’s gas storage capacity. The UK’s existing gas storage capacity is sufficient for around 6% of annual demand, or around 7 days of peak winter demand. And the maximum rate that that storage can release its gas is only sufficient to meet 38% of peak winter demand on cold days.
Yet most of our gas demand is concentrated (not surprisingly) in the winter months. We deal with the imbalance primarily by increasing the flows when they are needed (a) from our declining continental-shelf reserves, and (b) from imported natural gas, whether that is via the connectors to Norway and continental Europe, or through the LNG terminals.
Biogas production cannot be varied in the same way. It is necessary (for engineering and economic reasons) to produce the gas as continuously as possible. With the right incentives, it can provide a useful buffer for diurnal variations in demand through the installation of on-site gas storage. But it is not feasible to store biogas on-site to account for seasonal swings and peaks.
A significant increase in the contribution from biomethane will need a matching increase in our long-term gas storage capacity to hold the gas produced in summer for use in winter. That is particularly so if it is assumed that gas will help to insulate hybrid heating devices against the inefficiencies of their electric heating components in winter. Such a strategy would exacerbate the seasonal swings in gas demand.
The RHI is a minor contributor to our total renewable heat, most of which is provided statistically by domestic wood heating outside the RHI. So a radical increase in the contribution of biogas within the RHI may not represent a complete reversal of the government’s earlier assumptions that biogas would make a modest contribution because of resource constraints, especially given the competing demands for biogas for electricity, heat and transport, which will spread the limited resource even thinner.
But if biogas is not able to meet more than a small proportion of our heat requirements, that puts more onus on the other main plank in the Establishment’s plans for heat.
The 2012 “Future of Heating” strategic-framework document differentiated between three types of low-carbon heat: electric, biomass and solar.
Of these, heating technologies that use low carbon electricity hold particular promise, especially as electricity is universally available and technologies here are relatively established.” (§2.23, p.44).
“In contrast” (§2.24), biomass heat would be constrained by the supposedly limited resource and competing uses, and solar by its inverse correlation with heat demand (§2.25).
The follow-up “Future of Heating: Meeting the Challenge” action plan in 2013 fleshed out, with the help of supporting studies, how that vision might be delivered in practice. A number of different models produced different projections of the technology mix over the following 40 years, but the general pattern was similar in all of them: electricity would play an increasingly dominant part in heat supplies.
Electricity vs heat demand
There was some awareness from the start that there was a major technological and economic challenge for this vision: the disparity between current and projected patterns of electricity generation and patterns of demand for heat. Electricity generation patterns correlate to a reasonable extent with patterns of demand for electricity (without electrification of heat), and therefore only limited storage is required.
This correlation is weakening with the increased proportion of intermittent generation on the network, but the challenges of matching electricity supply to conventional electricity demand are of a different order to the challenges of matching low-carbon electricity production to heat demand.
Various government documents, including the “Future of Heating” publications, noted the challenge, without setting out how it would be resolved, nor implementing policies and incentives to deliver it.
One chart in particular reoccurs wherever this issue is discussed:
The chart was produced by Dr Robert Sansom of Imperial College. It shows synthesised half-hourly heat demand in 2010 (in red) compared to actual half-hourly electricity demand in 2010 (in grey).
Because heat is produced by many technologies, and much of it is not metered on a half-hourly basis like electricity, there are no short-interval statistics for heat demand. But short-interval figures for heat demand are exactly what are required to assess the imbalances between supply and demand that would occur with increasing electrification of heat. Dr Sansom therefore developed a methodology to convert (primarily) temperature and gas-demand data into synthesised figures for heat demand. Whilst one might make small refinements in this methodology, the fundamental approach is sound and produces a credible picture of half-hourly heat demand.
As the chart makes clear, heat demand is an order of magnitude greater than electricity demand, and the short-interval and seasonal variations are much greater. Peak demand for heat is roughly six times higher than peak demand for electricity. Demand for electricity varies by around 100% from trough to peak, in a reasonably predictable pattern. Demand for heat varies by over 1000% from trough to peak, and will vary significantly from day to day and from year to year.
This was a very important piece of work. The ramifications for the Establishment’s heat plans are massive, and have never yet been properly addressed. It is disappointing that further work to extend and update our knowledge in this area has not been carried out.
Without pretension to the academic rigour with which the original work was carried out, we have taken Dr Sansom’s methodology, with some minor variations, applied it to 2016 data, and made some comparisons that were not within the scope of Dr Sansom’s work.
We downloaded the Met Office’s hourly temperature readings from its stations around the UK, and Elexon’s half-hourly data for Actual Aggregated Generation per Type (report B1620),for calendar year 2016.
The electrification strategy depends crucially on the decarbonisation of electricity. Without that, electrification is a way of radically increasing, not reducing the carbon emissions from heating. The two key components of the long-term strategy to decarbonise electricity are low-carbon generation technologies and carbon capture and storage (CCS).
The government’s strategy for CCS lies in tatters, after most of the commercial research-and-development projects were closed or mothballed, as was the government’s support scheme to encourage its development.
So plans for heating with decarbonised electricity rely heavily on the expansion of low-carbon electricity generation. To be clear, that is not the planned expansion that is already expected to cost around £11bn p.a. from 2020 under the Levy Control Framework. That electricity is only enough to decarbonise around 30% of our electricity consumption for lighting and appliances.
If we want to further reduce the carbon emissions from our conventional electricity consumption and to electrify a substantial proportion of our heat, we will need to increase our low-carbon electricity generation several fold beyond the planned levels for 2020.
And that is not even the main challenge. The main challenge of such a strategy is the disparity between the production of that electricity and the demand that it is intended to meet.
To test the extent of this challenge, we compared synthesised hourly heat demand in 2016, based on Dr Sansom’s methodology, with the patterns of electricity production from solar, onshore wind and offshore wind generation. The readings were grouped into temperature bands, from below zero to over 18°C, as a weighted average temperature across the UK (weighted by regional population, to make the temperature figure as relevant to the heat demand as possible). To make it easier to compare the trajectories, the synthesised hourly heat demand is plotted against the left axis, and the electricity generation figures are plotted against the right axis.
As one might expect, photovoltaic electricity has a high inverse correlation with heat demand – in other words, PV electricity is generated when we don’t need heat and not generated when we do. It could make a good power-source for cooling, but it is a hopeless source of electricity for heating.
Wind generation does not have a significant correlation with heat demand, either positively or negatively. In other words, wind output is sometimes high and sometimes low when heat is needed, and it is also sometimes high and sometimes low when there is little heat demand.
Noticeably, wind output is low at periods of peak heat demand, when the average national temperature is below 4°C. So is solar. A heat electrification strategy would have to ensure that spinning reserve was available to meet these periods of low renewable-electricity generation and peak heat-demand.
That goes far beyond paying some of our old power stations to stay available under the Capacity Mechanism. As Dr Sansom’s chart illustrated, peak heat demand exceeds peak electricity production by an order of magnitude. We would need to install several times our current dispatchable electricity generating capacity to act as spinning reserve for these periods.
New generating capacity requires more support to act as spinning reserve than the retention of existing capacity. The capital cost of old plant has been recovered, which makes it feasible to operate on marginal cost. New plant will not be installed unless the support ensures that the capital cost as well as the running cost is covered.
The carbon benefit of electric heating is reduced if it relies on fossil-fuelled spinning reserve for periods of higher heat demand. We are already seeing the effect on the electrical efficiency of thermal generating plant from increasing capacity of intermittent renewable generation on the network. The thermal systems operate more intermittently, filling the gaps between periods of higher renewable electricity generation. The need to keep varying production reduces the electrical conversion efficiency. Their electrical conversion efficiency fell from 24.6% in 2013 (already significantly reduced from the days when fossil-fired generation dominated production) to 21.8% in 2015.
The use of two scales in the chart above could give the misleading impression that these generating technologies are in the same ballpark as heat demand. Here is the same chart with all lines on the same, left-hand scale.
The output from all our solar, onshore and offshore wind generation is barely visible at the scale of heat demand, during the periods when we need most of our heat. We don’t just have a problem that the patterns of production don’t align with the patterns of demand, but also that there is a complete mis-match of scale.
Would even a hundred times more solar and wind than we currently operate be sufficient to electrify our heat?
And what would we do with the output from those units during the warm and windy or sunny parts of the year, when their production greatly exceeded all the available uses for that electricity?
Trying to construct a best-case scenario for partial electrification
Let’s see if we can construct a best case for at least partial electrification.
The Establishment’s plans envisage heat pumps and hybrid gas boilers (which combine a heat pump with a gas boiler) supplying more than half our heat in 10 years’ time. But let’s cut that down to electrification of just one-third of our heat, to make the task easier.
And let’s assume that we use heat pumps for all that electrical heat, ignoring for now the difficulty of a roll-out of immature technology at that rate. So we need significantly less electricity than the heat that we need to deliver.
The vast majority of the systems that the Establishment envisages will be installed by 2027 are either air-source heat pumps (ASHPs) or hybrid gas boilers, whose heat pumps will be predominantly air-source, so we will use ASHP COPs to calculate the electricity required to meet the heat demand.
Let’s also assume that nuclear power contributes to the additional electricity needed to electrify heat. Nuclear output has a positive correlation with heat demand (i.e. it tends to produce more in cold than in warm conditions, probably because of the challenges of cooling nuclear power stations in summer). Nuclear will help to smooth out the mis-matches between heat demand and renewable electricity generation.
And let’s assume that the government subsidises massive investment in electricity storage, as a further device to align generation with heat demand.
Besides the direct capital and operating costs, there is a price to pay for storage in terms of round-trip efficiency. We have allowed for 70% round-trip efficiency, which is quite generous for long-term storage.
The following chart shows the surplus or deficit of electricity output relative to one-third of our heat demand, allowing for all excess being stored and deficits being supplied as required upto the installed storage capacity, on the basis that we install:
- additional capacity of solar, onshore wind, offshore wind and nuclear generation to match the current installed capacity (i.e. additional to the replacement of our ageing nuclear fleet, and to any additional capacity required to go beyond 30% renewable electricity for conventional electricity demand), and
- 30 GWh of additional electricity storage capacity (more than 30 GWh would not be economically feasible in this model, because capacity above that level would only be used infrequently across the year, making it impossible to justify the investment through its utilisation. To put it into perspective, the Pimlico accumulator tower, pictured at the top of this article, can store 86 MWh of heat. 1 GWh = 1,000 MWh).
The storage has dramatically reduced the number of periods where there is insufficient output and somewhat reduced (particularly in winter) the periods when there is excess output. Without that storage, the chart looks like this:
But, comparing the charts, notice two factors:
1. Summer excess
The storage has done little to address the excess in summer. That capacity of low-carbon generation greatly exceeds heat demand for most of the period from the beginning of May until mid October.
Because it exceeds it for a sustained period, the capacity of the storage is quickly used up and the excess output has to be spilled for the rest of the period.
This electricity cannot mostly be diverted to conventional electricity demand, because this is additional capacity to the low-carbon generation installed for conventional demand. In the periods when the heat-purposed low-carbon electricity is generating more than required, the electricity-purposed low-carbon electricity will already be meeting a high proportion of conventional electricity demand.
This excess in summer will have to be given away or even sold at a negative price (as has already occurred in countries with a lot of intermittent renewables). That may be a boon to uses that might be created to take advantage of intermittent negative prices for electricity, but it is a cost that would have to be borne by society, because the impact of negative prices on revenues to the low-carbon generators would deter investment.
2. Maximum deficit
The storage has not eliminated periods when there is insufficient output to meet heat demand. The maximum deficit is the same as it is without storage.
This reflects the reality that there are occasional anti-cyclonic conditions over most of the UK in most winters. These can linger for days or even weeks. At these times, temperatures are very low (i.e. high heat demand), the wind is minimal (i.e. low wind output), and the days are short and the sun low (i.e. low solar output).
The storage capacity is exhausted early on in these periods, after which spinning reserve is required to meet demand, just as it would be without the storage. So the costs and inefficiencies of maintaining spinning reserve remain, despite huge quantities of storage. They are just a smaller part of the output.
That means the carbon impact of their low efficiency is reduced, but their cost per unit output is much higher, as there are so few units from which to recover the capital and running costs.
Pushing the envelope
In case anyone is in doubt that additional storage is not economic and would not remove the need for spinning reserve, here is how the chart looks with 50 GWh of storage:
The deficit periods are reduced further, but not by much (which is why the additional storage capacity would not be economic), and the periods of maximum deficit remain the same (i.e. the same amount of spinning reserve is required).
And to illustrate the enormity of complete electrification, here is how the chart would look if that low-carbon generation were trying to meet all our heat demand:
There is still too much electricity output for most of the summer, and the spinning reserve that would be required to meet peak heat demand is now over 100 GW (several times more than our current capacity of spinning reserve).
Energy storage for seasonal variations in heat demand
Let’s be frank. Even the one-third-electrification scenario is not feasible:
- The cost of replacing our nuclear fleet and then doubling it, and doubling our capacity of onshore wind, offshore wind and solar generation, would be tens of billions of pounds a year, even if they could achieve good prices for their output.
- As their output would have a negative value for half the year, the level of support required would be higher still.
- The cost of 30 GWh of electricity storage would be another huge burden on the taxpayer.
- Nearly 30 GW of new spinning reserve would be yet another big cost for the Treasury to support.
- The heat pumps and hybrid heating systems would require further subsidy, potentially exacerbated by the impact on electricity prices of mechanisms to raise the revenue needed for the above support mechanisms from electricity consumers.
Are we prepared to spend something of the order of our annual defence budget on a strategy to convert one-third of our heat to decarbonised electricity?
The problem is the scale of the seasonal swings in demand for heat compared to the more manageable seasonal variation in conventional demand for electricity.
What we need is an affordable technology for storing renewable energy in summer and releasing it in winter during periods of high heat demand.
Biomass heat is that technology.
Biomass solar storage
Biomass takes solar energy and converts it into a stable fuel that can be stored and converted with simple, affordable technology.
- The forests are a huge, multi-year, infinitely-renewable energy store.
- Energy-crop plantations have a shorter rotation period but still acquire and store solar energy from one year to the next, let alone one season to the next.
- Logs (harvested trees) can be stored in large volumes at roadside in the forest, slowly reducing their moisture content without energy-input, waiting for collection and conversion to fuel during the heating season.
- Pellet plants densify biomass so that it can be transported longer distances at low environmental and economic cost, and stored in a much smaller space in a form ready for use.
- Bagging plants produce pallets that hold densified biomass in a form that can be stored without any special technology at all – in warehouses, garages or even (for hooded pallets) in open storage space, whether that is the producer’s, the retailer’s or the user’s property.
It is as easy to imagine the roll-out of this technology at large scale as it is difficult to imagine the electrification scenario described above.
1 million rural properties with 10-tonne pellet stores would hold enough fuel to last most of them for around a year. The production and distribution of the fuel could be spread evenly across the year. The fuel would be available to meet the variable heat requirements as required.
Unlike heat pumps, no changes would be needed to the properties’ heat distribution systems (i.e. radiators etc).
This would provide 50 TWh (1 TWh = 1,000 GWh) of energy storage, at a cost of approximately £100/MWh of storage. And it would support around 20 GW of heat production at periods of peak heat demand.
10 million urban/suburban properties with pellet stoves could hold a pallet of pellets in the garage, or for urban dwellers, collect a few bags at a time from their local retailer.
If the retailer had storage, they could buy a few pallets in summer at lower cost, ready to sell to their customers in winter. Or they could buy a pallet at a time from producers and distributors, who could hold stock to buffer summer production against winter demand in conventional storage facilities such as warehouses and yards.
The pellet stove would reduce the load on the primary heat source for the property during periods of peak heat demand, whether that heat source was a heat pump, a gas boiler (potentially using biomethane) or some other technology. This would significantly reduce the problem that these technologies cannot easily cope with the seasonality of heat demand, and allow them to operate on a more baseload basis.
A simple space-heating stove is a low-cost appliance, which makes it ideal for the purpose of peak-lopping the heat demand. The use of pellets enables widespread deployment with manageable storage-space requirements, and the assurance that only high-quality fuel with low emissions can be used in the appliance.
This would support another 65 TWh of heating fuel ready to be released as required, upto around 50 GW at periods of peak heat demand. No investment would be required in specialist energy storage equipment.
This model was tested accidentally in Sweden. At the World Sustainable Energy Days conference in Austria in 2015, Bengt-Erik Löfgren (CEO of the Swedish cleantech consultancy ÄFAB) reported that the use of wood pellets had gone into decline in Sweden for a couple of years after the government started promoting the deployment of heat pumps. Then demand for pellets started to pick up again. When they looked into it, they discovered that people were installing pellet stoves in properties where they had installed heat pumps, to ensure that they had adequate and affordable heat during cold periods.
Industrial biomass boilers
Larger heat users (primarily industrial) with more continuous heat demand would not need the benefits of densification to smooth out their seasonal demand and could take advantage of the lower fuel costs of wood chip and energy crops where available, making the most of the local biomass resource or potential.
The Forestry Commission’s Woodfuel Resource project estimates that the amount of woodfuel that could be available from Forest & Woodland, Primary Processing Products, and Arboricultural Arisings is a little under 8 million oven-dry tonnes a year, equating to around 40 TWh.
A 2015 report by the Energy Technologies Institute on Bioenergy: Enabling UK Biomass estimated the potential for energy crops in the UK at around 55 to 85 TWh annually in the 2030s, using 2.7 – 6.5% of UK agricultural land. These crops could be used to produce heat, electricity or transport fuels. The report does not predict what proportion would be available for heat, but on the basis of these estimates, this is another large resource if it is encouraged.
This reality has been perfectly apparent to most governments in developed nations for years. Tables 2.6 and 2.7 in the European Environment Agency's Renewable Energy in Europe 2016 – Recent growth and knock-on effects give the following figures for the contributions from the various renewable-energy technologies across all heat and power uses in Europe in 2015:
Final energy (ktoe)
Solid biomass for heating
Solid biomass for power
Biogas heat & power
Geothermal heat & power
Bioliquids heat & power
Perennial energy crops
Tidal, wave and ocean
Solid biomass for heating exceeds the combined contribution of all other renewable technologies except for hydro-electricity, and contributes more than double the latter.
But the British intellectual establishment has always felt itself to be immune from the benefits of learning from foreign experience and expertise. In their view, the UK is always exceptional, and its brightest minds know better than those pesky foreigners (unless foreign experience can be harnessed to defend the case that they want to make).
In their view, biomass has a negligible role to play in delivering the UK’s future heat requirements. The following charts show the core scenarios for various sectors from the Baringa/Redpoint modelling on which the 2013 “Future of Heating” action plan relied:
Could you spot the biomass heat in those charts? There are plenty of pie-in-the-sky technologies listed, but the most-practical and dominant renewable-energy technology in other countries is barely visible in any sector in the core scenario envisaged for the UK.
The Establishment offer a number of reasons why biomass cannot make a bigger contribution:
There is apparently not enough resource of sustainable biomass for any significant quantity to be available for heat, other than a tiny fraction for industrial heat.
It is never explained convincingly why all the other uses for biomass have priority over this limited resource. The ability of solid biomass to act as an affordable, seasonal store of solar energy means that, if it has to be prioritised, it should be prioritised for the use that is most difficult to decarbonise by other means because of the massive variations in demand.
Nor is it ever explained persuasively why the biomass resource is assumed to be so much more limited for the UK than in other countries (such as Denmark or Italy, which are no more heavily forested than us). But in any case, how limited is it really?
I addressed this issue in my previous blog post for the WHA.
To put it into the context of this post, all of the wood pellets required for the scenario I described above (1 million pellet boilers and 10 million pellet stoves, requiring by my estimate around 23 million tonnes of pellets annually) could be produced from around 20% of the decline in industrial wood demand in the USA between 2005 and 2010. In other words, all we need is one-fifth of the wood for which there is no longer demand in one other country.
That is not contributing to deforestation. In fact, it is contributing to afforestation. As that blog post demonstrated, demand for wood products stimulates afforestation, and a lack of demand results in stagnation, lack of management, and insufficient replacement of dying stock. Biomass can provide the demand to make it worth continuing to plant and manage forests around the world.
Some pressure groups dislike biomass ostensibly because they believe that it contributes to deforestation and the loss of habitat. They appear to be unable to differentiate between anecdote (for which the examples that they cite are no doubt genuine) and statistics (which demonstrate that they are wrong in the generality, regardless of the exceptions that they identify). If we have to stop doing things because some people breach the rules, we will have to stop all forms of human activity.
To reinforce their arguments against biomass, these groups (and other groups supported by industries that want the wood fibre for themselves) invented the concept of “carbon debt”. According to this theory, it is irrelevant that the carbon released from biomass combustion is reabsorbed by growing trees, because the process increases atmospheric carbon in the short-term.
This is an invalid argument, based on a system-boundary error. We explain why this is a mistake in simple terms that even these pressure groups might understand if their minds were open, in a short animation that we had produced for the Wood Heat Association and the UK Pellet Council.
There has been recent attention to the contribution of wood stoves and boilers to the poor air quality in some of our cities.
There is a lack of proportionality in the reporting of the relative significance of vehicle emissions and wood-burning appliances. Boilers in particular are falsely accused – RHI statistics show that the number of installations in London is negligible.
But, to the extent there is a problem, it relates largely to two factors:
- Inadequate combustion conditions, such as may be created in open fires or old stoves, and
- Poor-quality fuel, such as recovered wood, wet wood or non-wood combustibles (e.g. plastics).
There is no practical way that people can be prevented from using their open fires and old stoves, nor that the fuel they use can be controlled. The best way to tackle this problem would be to encourage the replacement of these installations with a new, good-quality appliance that can only accept high-quality fuel.
That is exactly what a roll-out of pellet stoves would achieve. All kinds of fuel can be used in multi-fuel stoves, risking poor emissions even if the appliance itself is good quality and well-installed. But pellet stoves can only burn wood pellets, and the only form of wood pellet widely available in bagged form is the highest-grade: ENplus A1.
The mass replacement of open fires and old stoves with well-installed new pellet stoves should have a beneficial effect on air quality.
A presentation by Colin Meek of the Renewable Energy Consumer Code at the WHA’s annual conference in November highlighted the unfortunately-high proportion of problem installations.
This is largely a function of the way that the market was over-stimulated by the first phase of the RHI, creating a gold rush that attracted too many cowboys. There were few quality constraints on eligibility for the RHI. Most customers were in too much of a rush to grab the best tariffs before they were degressed to take the time to understand the quality issues and look into the reputations of prospective installers. In any case, consumer protection legislation has (near enough) killed caveat emptor. Many customers and their cowboy installers tried to game the system by installing boilers that were too large, in order to maximise their Tier 1 income, without realising that the negatives from an over-sized system would outweigh the supposed benefit.
Standards were particularly absent from biomass storage systems, the vast majority of which did not comply with industry guidelines. Yet inadequate fuel-storage and -handling is probably the biggest cause of problems in smaller biomass systems. These fuel systems did not lie within the effective scope of the accreditation schemes for equipment and fuel, let alone within constraints set out by the RHI.
These problems could be addressed with the benefit of hindsight from phase 1 of the RHI.
- We know from the level of installations before and after the degression steps the level of support at which the economics became marginal. It would be easier with the benefit of this knowledge to design a mechanism that provided no more than sufficient incentive, to avoid creating a new gold rush and posse of cowboys.
- The mechanism could make compliance with industry guidance a condition of eligibility.
- More broadly, the government could support efforts to put together a comprehensive quality-assurance scheme for biomass heating equipment, and tie that to the support mechanism.
- One of many benefits (besides cost) of a greater focus on pellet stoves for smaller properties, leaving biomass boilers to larger properties, would be that there are no significant fuel-handling issues for pellet stoves. The skills required for a good-quality installation of a pellet stove are significantly more limited than for a good-quality biomass heating and fuel-handling system.
Biomass heat is one of the cheaper forms of renewable energy. Its opponents try to twist logic to argue that it is nevertheless not good value in one of two ways:
1. It has no role in our future heat supplies, so any money spent on it is down the drain, even if it is currently cheaper than the “strategic” technologies.
2. Small biomass is more expensive than larger biomass, so any support above the level needed to deliver large biomass is effectively deadweight cost.
These arguments rely on such palpably bad logic that it should be obvious that their purpose is less to convince and more to deflect. But bullshit baffles brains (sometimes).
(1) is circular reasoning: Biomass has no future. We should plan our future energy systems on technologies that have been decreed to be “strategic”. Those technologies consequently dominate the models of our future heating supplies. Because they will be such major contributors to our future heat requirements, money spent on them is well-spent even if they are currently expensive. Conversely, money spent on biomass is wasted because it has no future. So biomass is “expensive” in strategic terms, even if it is cheaper than the alternatives at the moment. And if biomass is expensive, why would we incorporate it in our plans for future heating?
Of course, if we accept this logic, we should never use whatever technology is most cost-effective now, if “experts” have decreed that a more expensive technology will be more significant in the future. Price signals are dead; economic evolution is replaced by central planning.
It is economically illiterate, but good economics is a luxury that the British Establishment has always found dispensable if it gets in the way of them deciding what is right for everyone.
(2) is a false dichotomy. Small and large biomass are not the only options. It is unlikely that large biomass can exhaust the potential of biomass heat.
The true alternatives are all the renewable-heat technologies. Small biomass heat is cheaper than most of the other technologies. We cannot meet our objectives to decarbonise heat with technologies that are cheaper than small biomass heat. If we could, the Establishment’s plans should not be promoting technologies that are much more expensive than small biomass.
If the various arguments used to diminish the potential of biomass heat are false, for the reasons explained above, then small biomass heat should not be compared solely with large biomass heat, but also with the other options for decarbonising heat, most of which are more expensive.
The straightforward way to discover which are the economically-optimal solutions to reduce our carbon footprint would be to apply a carbon price to all emissions from fossil fuels (and to equivalent factors that increase or decrease atmospheric concentrations of greenhouse gases).
There may not be the political will to implement such a measure, but imagining such a world provides a useful thought experiment to judge whether the alternative measures are achieving a similar effect. What combination of technologies could we envisage would be implemented to the extent of achieving our environmental objectives, at a lower carbon price than would deliver small biomass heat?
The deployment of biomass heat described above is a feasible and deliverable option using established technologies to radically reduce carbon emissions from heat production.
Once one considers the reality of the scale and seasonal variations in heat demand, the patterns of production of low-carbon electricity, and the challenges of long-term electricity storage, what alternative strategy could achieve similar results for similar costs, without relying on magic technological bullets that have not yet (after nearly 30 years of support for low-carbon electricity) demonstrated their commercial viability?