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6. Economics of Biomass Production and Consumption in Scotland

6.1 Background

Due to the wide variety of feedstocks, end-products, conversion technologies, fuel chains and production scales, a full evaluation of the economics of biomass systems is far from straightforward (Dournbourg & Faijj 2001). This is made even more difficult when the results of different studies are compared. As discussed in Chapters 4 and 5, different studies use multiple system boundaries and rely on inconsistent underlying assumptions, which are not always explicit. Furthermore, the results of individual studies are often tailored to a specific set of conditions that best reflect the region or country they are intended to represent. In this chapter, we present literature findings as reported and provide an assessment of their likely relevance for Scotland.

The economics of biomass production and consumption necessarily encompasses a multiplicity of different aspects. Biomass energy is inserted within a complex web of cross-cutting sectors including agriculture, forestry, energy, transport, rural development and climate change mitigation such that the term 'economics' needs to be broken down into distinctly manageable segments. The starting point for this chapter is that economics necessitates an analysis of the costs required and the benefits afforded by a particular system. This idea is embedded within the concept of cost-effectiveness, which can be described as the maximum amount of benefits that can be derived from a set cost or, inversely, the minimum costs for which a particular set of benefits can be obtained.

The costs considered will include the costs to the fuel provider, the investment costs required for specific technologies, the production/generation costs associated with the biomass end-use (heat, electricity/ CHP, transport fuel), and the carbon abatement costs of various technologies. Benefits considered will be impacts on rural development, climate mitigation benefits and the opportunities arising from trade in biomass.

Biomass energy systems exist in a market in which they must compete with other energy technologies, including fossil fuel-derived, nuclear and renewable. Thus, comparisons will be made between biomass systems and competing technologies whenever this is possible. The chapter will also consider the incentives in place to make biomass competitive with conventional fossil technologies.

6.2 Heat

6.2.1 Feedstock Production Costs

Production costs can be defined as the costs incurred by fuel providers to specifically grow or harvest feedstocks for energy purposes. Processing costs for forestry and agricultural residues are not considered here as production costs, but are included in the section on 'fuel costs' (Section 6.2.2). Production costs are important as they provide an indication of how likely farmers are to take up the cultivation of an individual crop. For uptake of bioenergy crops to occur, the gross profit margin for those crops must be greater (with or without incentives) than the gross profit margins of conventional crops or the set-aside payment.

Given their early stage of development, a full assessment of the economics of energy crop production is still fraught with uncertainty ( RCEP 2004). Short-rotation coppice willow is only just beginning to be grown on a commercial scale in Scotland and miscanthus and other energy grasses have only been grown on an experimental scale so far. Results presented in this section are therefore representative of other locations in the UK or have yet to be confirmed in practice, and therefore caution must be applied if attempting to extrapolate to Scottish conditions.

Short-rotation Coppice

Several costs must be borne by farmers who opt to grow short-rotation coppice. These include costs with site preparation and planting, application of herbicides to prevent the germination of weeds, addition of fertilizer to maintain site productivity, as well as harvesting costs (Mitchell et al. 1999). In addition to this, there is the potentially very expensive step of stool removal if the farmer wishes to revert to arable land use. Unlike conventional annual crops, there is a delayed first harvest of 3-4 years that must be taken into account when comparing economics of different crops.

Dawson et al. (2005) carried out an economic feasibility analysis of SRC willow production in Northern Ireland in which a 25-year life cycle was assumed for the crop. They estimated establishment costs of £2,000 ha ^-1 which included fencing, land preparation, planting and weed control and harvesting costs of £500 ha ^-1 plus an additional £500 ha ^-1 to remove the stools at the end of the crop life cycle. Based on an average yield of 12 odt ha ^-1 yr ^-1 and assuming a price of £30 odt ^-1, the authors calculated that the production costs exceeded the benefits received, even when a £600 ha ^-1 one-off woodland grant was included in the calculations, so that the net profit margin was £-26 ha ^-1. At a yield of 10 odt ha ^-1 yr ^-1, losses were even more pronounced, being 20% greater than at a yield of 12 odt ha ^-1 yr ^-1. Indeed, the study suggested that positive net margins could only be achieved at yields of 14 odt ha ^-1 yr ^-1 and above. Even with the subsidies available, therefore, the economics of short rotation coppice willow were found to be marginal at best.

Similar findings were presented by Boyle (2004) for England and Wales, where an average yield of 10 odt ha ^-1 yr ^-1 was assumed, with establishment grants of £1000 ha ^-1 for non-set aside land and £1600 ha ^-1 for set-aside land. The final conclusion was that SRC could not be economic unless grown on set-aside, with establishment grants and with yields at or above 10 odt ha ^-1 yr ^-1. Provided these conditions were met, however, an annual income of £189-360 for SRC willow was deemed possible. The differences in the returns calculated by Dawson et al. and Boyle are largely reflective of underlying differences in establishment grant rates, differences in establishment costs and in the cost of the fuel per hectare. Illustrative establishment costs for SRC willow, as presented by Boyle for England and Wales, are reproduced in Table 6.1.

The only Scottish appraisal of the economics of SRC willow found in the literature was conducted by Booth et al. (2005a) for the Fife region. Assuming an average yield of 9 odt ha ^-1, a production period of 16 years and a wood chip price of £26 t ^-1 at 40% moisture content, an NPV of £543 ha ^-1 with an internal return rate of 15% and pay back period of 7 years was estimated. It is worth mentioning that this calculation assumed a Scottish Forestry Grant of £600 ha ^-1 and this has now increased to £1000 ha ^-1.

Table 6.1 Illustrative Establishment Costs for SRC Willow

Source: Boyle (2004)

Increased yields could make SRC willow more profitable with a recent study indicating that a 30% increase over current yields could make the crop an attractive alternative to established annual crops such as barley (Lek Ltd. 2004). Exploitation of willow bioremediation potential has been suggested as one means to improve the crop's gross profit margin (Dawson et al. 2005). Wastewater and sewage sludge are both products which incur high gate fees and their treatment through willow bioremediation has been calculated to increase gross profit margins to between £480-930 ha ^-1.

Energy Grasses

As with SRC willow, the lack of commercial energy grass production in Scotland means that accurate yield estimates are not possible and makes economic assessment problematic. Most of the economic appraisals carried out so far have been for miscanthus, an energy grass which is not well suited to Scottish conditions (Towers et al. 2004). Analyses undertaken thus far indicate that the economics of energy grasses is very similar to that of SRC willow, although there are some differences in establishment and tending costs. For a yield of 12 t ha yr ^-1, Boyle estimated an average annual return of £339ha ^-1yr ^-1 over a 15-yr period, within the estimated range of SRC willow. Due to high expenses with rhizomes, the establishment costs of miscanthus are higher than with other energy grasses (Riche 2004). On the other hand, reed canary grass may necessitate higher tending costs as a function of the crop's higher fertilizer requirements.

Short rotation Forestry ( SRF)

Information on the economics of short rotation forestry in the UK is not as readily available as for SRC coppice, although a recent study on this topic was published by LTS International for the Forestry Commission (Hardcastle et al. 2006). Establisment costs, which do no vary significantly between different species, were calculated to be in the region of £2,800 ha ^-1, including the cost of fencing. Large differences in productivity and growth rate between species result in varying returns as is shown in Table 6.2. Alder and birch were found to have much lower rates of return than ash, but Eucalyptus had the highest return rates of all species tested. The authors of the study also tested a simple model to compare economics of SRF species under coppicing. Due to much lower establishment costs, coppicing was found to markedly improve IRR. The study concluded that 'the proposed Scottish Forestry Grant level of £1,000 per ha is not sufficient to make SRF an attractive investment unless either a wood price approaching £20 per wet tonne (£40 odt ^-1) can be obtained or substantial cost reductions can be made.'

Table 6.2: Illustrative Internal Rates of Return for SRF Species Under Different Grant Scenarios at £40 odt ^-1

Source: Hardcastle et al. 2006

Forest Material Extraction

Dawson et al. (2005) estimated that harvesting costs for small roundwood and forestry residues in Northern Ireland were between £5.50 and £10.50 per green tonne (£ 11 - 22 odt ^-1). The harvesting cost of woodfuel from forests in Scotland according to the Forestry Commission is £10.00 to £13.00, although costs can be significantly higher depending on site conditions (Forestry Commission Scotland 2006). When costs are higher, a loss is incurred by the grower to harvest and deliver to the market.

6.2.2 Fuel Costs

Processing Costs

To ensure efficient combustion, biomass feedstocks must undergo some processing steps, which usually involve chipping into manageable dimensions and drying to reduce moisture content. Dawson et al. (2005) estimated chipping costs of approximately £7 odt ^-1 for Northern Ireland, although the Forestry Commission recommends £10 odt ^-1 as a more realistic figure for Scotland (Forestry Commission Scotland, personal communication). Dawson et al. (2005) suggested assisted drying costs of £7.50 odt ^-1 for woody crops such as SRC willow, small roundwood and forestry residues. Suurs (2002) reported costs of a similar magnitude for drying chipped biomass in Sweden (4-15 € odt ^-1).

Some biomass fuels such as pellets or briquettes require an additional densification step. AEA Technology (2003) published a report for Scottish Enterprise Forest Industries Cluster on the potential for pellet production in Scotland and estimated that the total costs of producing pellets in Scotland would be £68 - 73 t ^-1 (ex-works). This included costs associated with feedstock (sawdust) costs, drying costs and pelletising costs. This cost, according to the report, would allow a profit from Scottish pellet production, providing the costs of imports remained high.

Transportation Costs

Transportation costs of biomass obviously depend on the mode of transport utilised and the transportation distance involved. Due to their lower energy density, the transportation costs of biomass fuels are high in relation to fossil fuels. Pellets, due to their higher energy densities have lower transportation costs per unit of energy produced than wood chips or logs. Table 6.3 provides illustrative values of transportation costs involved for several wood fuels over a range of distances by truck or ship. Once again, these values can only be taken as being indicative of Scotland.

Table 6.3: Illustrative Transportation Costs of Wood Fuels

Source: Suurs (2002)

Transportation costs are likely to be very important in the overall economic viability of bioenergy schemes in Scotland. The fragmented nature of the forestry resource will mean, for example, that highly centralised plant fuelled with forestry residues will require large transportation costs. The overriding principle is that the closer the heat/electricity plant is to the biomass resource, the more economic sense the initiative will make. The Royal Commission on Environmental Pollution Report (2004) concluded that forestry residues have a mean economic transport distance of between 30 km and 50 km, with the mean economic distance of other fuels being even less than this.

Final Fuel Costs

The cost of the fuel plays an important role in the overarching economics of biomass energy systems. The cost of woody fuels used for heat depends heavily on the moisture content. As shown in Table 6.4,woody fuels used for heat such as wood chips from forestry material or SRC typically cost £40-55 t ^-1 at 30% moisture. An indicative cost for high quality wood chip from small roundwood or sawmill slabwood is £55 t ^-1 (£77 odt ^-1). Poor quality chip at high moisture content might be £30-35 t ^-1 (Forestry Commission Scotland, personal communication) Pre-processed fuels such as wood pellets are the most expensive, with the price of wood pellets in Scotland for 2006 estimated to be about £150 odt ^-1 ( SDC 2005, Rippengal 2005). An important factor in high pellet prices is that there are no pellet-producing units in Scotland, so the pellets need to be imported.

The price of bioenergy feedstocks needs to be competitive with that paid by alternative industries and growers need a return from their product. Chipwood currently has an average price in Scotland of £18.50-19.50 per green tonne (~ £38 odt ^-1) delivered to the sawmill, with harvesting costs accounting for approximately two-thirds of the cost and haulage the remaining third (Forestry Commission Scotland 2006). Chipping costs must be added to this, so that the final cost is > £40 odt ^-1. This is the cost that developers must be willing to pay if a steady local wood fuel supply chain is to develop.

Table 6.4: Indicative End Prices of Selected Biomass Fuels for Heat, Compared to Fossil Fuels

Source: Rippengal 2005. Prices refer to

6.2.3 Plant Economics

Capital and Operational Costs

Biomass heat systems require large storage areas and specialised delivery systems, which can greatly increase the capital costs of these schemes in relation to alternative fossil fuel systems. In many cases a separate boilerhouse is needed, whereas natural gas and oil-fired boilers can be easily integrated into the building being heated ( SDC 2005). Capital costs are also dependent, to a certain extent, on the fuel used, with wood pellets requiring less storage area and less specialized delivery systems than wood chips, which consequently means that capital costs are reduced. Comparisons of different small-scale heat systems with approximate prices for alternative heating systems are provided in Table 6.5. The values presented in the table refer to specific appliances covered in the SDC report, but can be used to compare costs with equivalent fossil fuel systems. According to the Sustainable Development Commission (2005), capital costs of wood-fuel heating schemes are currently up to five times the price of equivalent fossil fuel based systems, which acts as a disincentive to market development. Wood Fuel for Wales (2006) presents generic estimates of capital costs for wood fuel heating systems of £110-265 kW ^-1, as opposed to £60-115 kW ^-1 for equivalent gas or oil heating systems. This high initial cost can act as a disincentive to woodfuel installations, even though long-term fuel savings may occur in relation to some fossil fuel alternatives (Table 6.7). It must be remembered that the wood fuel supply chain in Scotland is still at an early stage of development and the industry has not yet experienced the downward price trend that results from increasing sales volumes.

Table 6.5: Ilustrative Capital and Operating Costs of Small-Scale Biomass Heat Systems

Source: SDC (2005). Fuel costs for running costs calculations were £45 t ^-1 for wood chip (@35% moisture), £150 t ^-1 for wood pellets and 32p litre ^-1 for oil.

Operating costs of small-scale heat systems are influenced by a host of variables including boiler efficiency, fuel costs, regular maintenance costs, servicing costs and management expenses if run by an ESCO ( SDC 2005). As shown in Figure 6.1, running costs of wood fuel systems are currently very competitive against oil-fired alternatives.

The variability associated with woodfuel heating systems costs is very high. For schemes in Wales, total project costs (including fuel storage, handling and project design) were found to range from £64 kW _th^-1 to £1800 kW _th^-1, although £300-600 kW _th^-1 was considered the normal range for project planning (Dan Gates, personal communication). The prices at the higher end of the spectrum relate to installations in stately homes, which have more complex design requirements due to the high visibility and complexity of the heating systems of the buildings. In general, scale will also be a factor with smaller systems have a disproportionately high cost.

Internal Rates of Return

The recent Carbon Trust Biomass Sector Review investigated the economics of heat systems of different scales under varying oil prices and levels of government incentives. The review concluded that the economics of residential biomass-fired boilers and stoves were significantly worse than that of the other systems investigated, principally because of lower load factors (Carbon Trust 2005). Howerver, the report did not look at domestic use in much detail and iog boilers can be relatively cheap to install when people collect the wood for themselves (Forestry Commission Scotland, personal communication).

Besides residential heat systems, very small to small scale (.2 MW to 2 MW) commercial systems and large industrial heat systems (30 MW) were also assessed in the Carbon Trust Report. Of these, the small scale (2 MW) systems were found to have the highest rates of return (Table 6.6), and the rates of return of the heat systems were generally greater than for any of the electricity options. In fact, in the absence of government incentives, small heat was the only system where positive rates of return were possible. In all cases, oil price was a key economic driver. The simulated economics of the large heat plants was worse than that of small heat plants as a result of increased sensitivity to revenue changes due to low unit capital costs. Oil prices therefore had a greater effect at this scale than at the small heat scale. The results of the study are of course dependent on the specific assumptions made regarding debt level, interest rates and incentive levels, among others. Of the fuels tested, better returns were obtained for mixtures of waste wood and forestry woodchip and for straw than for energy crops and woodchip from forestry. At the time of preparation of this report, oil prices stood at over US$70/barrel. Continuation of this trend will make biomass technologies increasingly more competitive.

Table 6.6: Illustrative Rates of Return for Different Scale Heat Technologies

Source: Carbon Trust (2005).

6.2.4 Delivered Heat Costs

The delivered heat cost can be viewed as the minimum price that a heat supply company could charge to cover its costs, without considering a profit margin ( SDC 2005). The recent 'Wood Fuel for Warmth' report provided simulated cost comparisons for small-scale woodfuel heat systems of different sizes. For woodchip-based systems, the study estimated that the delivered heating cost for a 460 kW _th district heating scheme would be approximately 3.3 p kWh ^-1 and therefore more expensive than natural gas and only marginally cheaper than an oil-fired boiler of equivalent size. In the case of a 150 kW _th boiler for a single building, however, the estimated delivered heat cost was 2.0 p kWh ^-1, which represented a significant saving in relation to oil and was even less expensive than natural gas (Figure 6.1). The difference in the two systems was due to differences in operational costs, which were considered to be significantly lower than for the district heating scheme.

Figure 6.1: Illustrative Delivered Costs of Heat from Biomass and Fossil Fuel Systems

(a) 460 kW District Heat System.

(b) 150 kW Wood Chip Boiler in Single Building

Source: SDC 2005. Based on wood chip price of £45 odt ^-1.

Figure 6.1 shows that heat generated form wood chip or pellet is already strongly competitive with that of oil under current oil prices. It has even been reported that the cost of wood fuel heating in some locations may even be as low 50% that of oil (Highland Wood Energy 2006). Increases in gas prices over the last year mean that woodfuel is currently competitive with natural gas. The National Energy Foundation's Logpile website, for example, estimates that cost of delivered heat from woodchips as being 1.5 - 2.1 p kWh ^-1, while the delivered cost of heat from natural gas is estimated to be 2.8 p kWh ^-1 (National Energy Foundation 2006).

Heat from pellets is still considerably more expensive than that from woodchips (3.0 - 3.5 p kWh ^-1 vs. 1.5 - 2.1 p kWh ^-1), but the issue of scale is also important. Pellets may be more economical than wood chips at smaller heating loads, for example (20-200 kW) due to lower capital installation costs resulting from simpler feed mechanisms and reduced space requirements (Wood fuel for Wales 2006). Fuel savings are less, but ease of use of pellets can be important at this scale of use. Pellet systems are also likely to become more cost-effective in the long-term as the cost of pellets is reduced and increased volumes of equipment sales reduces the cost of pellet boilers (Forestry Comission Scotland,, personal communication). From information on installations to date, the Forestry Commission estimates that, provided capital costs are minimised and grants are available, wood chip is economic from 60 kW and could be considered in some circumstances from 30 kW.

6.2.5 Carbon Abatement Costs

The methodology used to calculate carbon abatement costs varies from study to study, so that it is difficult to directly compare absolute abatement costs from different studies. Studies which utilise a consistent methodology to compare different options thus provide more meaningful information. Future Energy Solutions (2005) calculated carbon abatement costs for a range of different renewable heat technologies in relation to gas and oil by dividing the difference in cost for 1 kWh heat supplied from biomass and that of fossil gas or oil by the total carbon savings. Of all the renewable systems considered, biomass was found to offer the most cost-effective carbon reductions (Figure 6.2), although the carbon abatement costs of residential biomass heat systems were still found to be prohibitively high (> £1000 t C ^-1).

Using a different methodology, the Carbon Trust (2005) also estimated carbon abatement costs for different biomass heat and electricity systems. The carbon abatement cost defined in the Carbon Trust study was 'the cost per tonne of carbon saved to bring the net present value ( NPV) of an investment to zero at a discount rate of 15% without any government incentives'. Among all the heat/electricity options investigated, small-scale biomass was found to present the most cost-effective carbon savings. The carbon abatement costs of different heat technologies, as provided in the Carbon Trust Report for a crude oil value of $30 bbl ^-1 crude, are shown in Table 6.7. Small and large heat technologies were both calculated to have a carbon abatement cost around £30 tC ^-1. Very small scale systems, on the other hand were found to require higher carbon abatement costs, in the range £90-100 tC ^-1 and residential systems were found to be prohibitively expensive, as in the Future Energy Solutions study. The results of the two studies were also similar in that industrial systems (2-30 MW) were found to provide lower carbon abatement costs than smaller commercial units.

Figure 6.2: Comparative Carbon Abatement Costs (Relative to Gas) of Selected Renewable Heat Technologies.

Source: Future Energy Solutions 2005

Table 6.7: Carbon Abatement Costs of Heat Technologies of Different Scales

6.2.6 Market Prospects

Recent studies by the Scottish Sustainable Development Commission (2005) and for Scottish Enterprise (Rippengal 2005) have emphasized the market opportunities available for the development of the small-scale wood heat industry in Scotland in the immediate future. Market opportunities appear to be especially attractive in areas that are not penetrated by the natural gas network, where coal, LPG and heating oil would represent the main fuel competitors ( SDC 2005). The Rippengal report provided an exhaustive evaluation of the current opportunities available for wood heat penetration in Scotland. The salient conclusions of the report were as follows:

• The public sector can be a key player in pioneering wood fuel market development. This includes prisons, hospitals and other 'high load' users as well as local authorities.
• Within the public sector, social housing may have an especially significant role to play, as there is a close association between these households and fuel poverty issues.
• Wood chip pellets may play an important role in opening up market opportunities that would not always be present for other forms of wood fuel.
• The immediate opportunities for wood fuel are in the off-gas areas (Figure 6.3), where wood fuel can already be competitive with other fuels.
• Individual technologies all have a part to play in developing the wood fuel market. These include log boilers in farms/estates, small and medium wood-chip boilers in public sector buildings and large wood-chip boilers for the industrial sector.

Figure 6.3: National Gas Transmission System in Scotland

Source: National Grid ( www.nationalgrid.com)

The early stage of development of the biomass market in Scotland means that there are inherent risks involved which can result from disjointed supply chains and price volatility. The risk factor often manifests itself in a 'chicken and egg' situation where investors will not fund biomass developments because of the lack of a stable supply chain, while potential suppliers remain hesitant to take up biomass production because of the perceived instability of the market. This can be a greater problem for growing short-rotation coppice, where 3-4 years are required for the first harvest. The development of stable markets will serve to reduce risk and it is therefore of paramount importance that all the links in the supply chain are properly thought out.

Employment Prospects

Several estimates of biomass industry expansion on employment exist in the literature, although the background calculations are not always presented in a clear manner. The recently published 'Economic Impact of Wood Heat in Scotland' by the Fraser of Allander Institute which supported the Rippengal review on biomass heat opportunities in Scotland estimated that by 2020, 2000 new jobs could be created per year by the biomass heat sector in Scotland if it were to represent 5% of the total heat market. In addition to this, the report estimated that 6000 new jobs would be created during the construction phase as a result of the increased number of biomass heat systems being installed.

Other rough estimates of employment opportunities generated by development of the biomass sector in Scotland have also been put forward. The Sustainable Development Commission for Scotland (2005) estimated that small CHP could create 15 jobs MWe ^-1 while industrial-scale heating systems could create 1 job per 200 kW _th boiler.

6.2.7 Incentives and Grants

Considerable focus on electricity has meant that the renewable heat sector has been largely sidelined until very recently. There are well-defined targets for renewable electricity and an accompanying legally binding instrument (the Renewable Obligation Scheme) is in place to ensure those targets are reached. The heat sector, responsible for about 50% of Scotland's total energy consumption ( AEA Technology 2006), has not benefited from such measures. Fortunately, this is beginning to change and there is growing awareness of the importance of reducing greenhouse gas emissions associated with heat energy production and consumption. Recently, plans were announced for a renewable heat strategy that would include an 'ambitious target for its generation' (Scottish Executive 2006). Initially, the debate centred on whether a renewable heat certification scheme analogous to that used in electricity should be introduced. There has been gradual acceptance, however, that this approach is not really workable for heat due to the highly fragmented nature of the supply market (Biomass Taskforce 2005). A robust support structure coupled to adequate renewable heat targets is thought to be the best way forward, as exemplified in the Scottish Executive's commitment to support biomass, to develop a Biomass Action Plan and Renewable Heat Strategy and to meet the targets set out in the Climate Change Programme.

Most of the 50 or so modern woodfuel heating schemes in Scotland have received funding from the Scottish Community and Householder Renewables Initiative ( SCHRI), financed by the Scottish Executive and managed jointly by the Energy Saving Trust and Highlands and Islands Enterprise. The scheme finances up to 30% of capital costs and up to £4000 is available to householders while a larger proportion of costs and as much as £100,000 may be available to community groups (Scottish Parliament 2006). Other grants exist which may facilitate the expansion of the biomass heat sector in Scotland. These have been extensively reviewed in recent studies (Rippengal 2005, SDC 2005, FREDS 2005), and are therefore not dealt with in great detail here. Annex 5 provides a non-exhaustive list of the main grants schemes in place that promote the development of the biomass heat sector in Scotland. The general consensus at present is that there is no cohesive grant structure that allows for strategic development of bioheat in Scotland, with the available grant schemes being disjointed and unnecessarily complicated (Scottish Parliament 2006).

6.2.8 Relevance of Literature Coverage to Scotland

Two recent reports, one by the Sustainable Development Commission for Scotland (2005) and one by Rippengal (2005) for Scottish Enterprise have provided much information on the potential of the wood fuel market for Scotland and on competitiveness with fossil fuel alternatives. Although a rough economic impact of different wood fuel scenarios was carried out by the Fraser of Allander Institute (2006), a full economic appraisal of different options is necessary to add weight to these findings. Again, studies that analyse the carbon abatement costs associated with delivering biomass heat under different scenarios would undoubtedly be very useful.

6.3 Electricity/ CHP

6.3.1 Production Costs

Production costs for the main feedstocks of relevance for electricity/ CHP production from biomass are the same as those for heat production and have already been described in section 6.2.1.

6.3.2 Fuel Costs

In a similar manner to production costs, the fuel costs that apply to electricity feedstocks also apply to heat feedstocks and have been discussed in section 6.2.2.

6.3.3 Plant Economics

The flexibility of biomass energy systems means that a range of possible conversion technologies can be used to generate heat or electricity at different scales. As discussed in chapter 2, industrial heat/power can be generated through biomass by gasification, pyrolysis and combustion, with the latter two currently at an experimental stage.

Capital & Operating Costs

The capital costs involved in the generation of power/heat from biomass are being increasingly recognized as presenting a major obstacle to the maturation of bioenergy fuel chains ( SDC 2005). Besides the main combustion/gasification systems, fuel processing technologies are often necessary which increase the costs. For proper combustion, fuel often needs to be dried, with appropriate equipment entailing capital costs of up to £20,000-30,000 (Dawson et al. 2005), although this obviously depends on the scale of the application. The overall plant economics will depend largely on the size of the plant and the technology employed. Costs associated with gasification systems, for example, are higher than with systems which rely on the operation of steam turbines. The details of individual cases are highly variable and it is often difficult to derive 'representative' results. Costs such as grid connection, public service obligations and supplier margins, for example, are heavily influenced by site location and the capacity of the connection. Table 6.8 presents illustrative figures of capital investment associated with different electricity/ CHP systems, suggested by Boyle (2004) and obtained from the Wood Fuel for Wales site ( www.woodfuelforwales.org.uk). The absolute values presented should not be paid undue attention, but the comparison with generic costs of natural gas and coal systems is useful.

Table 6.8. Illustrative Capital Costs of Different Biomass CHP/Electricity Technologies

Source: Boyle (2004),www.woodfuelforwales.org.uk(accessed 2006), Faijj 2006

Large-scale biomass gasification plants are only operative on a demonstration scale at the moment, meaning that estimates of plant economics once fully commercial are currently highly speculative. Capital costs of current demonstration projects range from £2300-3400 kW _e^-1, but this is expected to fall to £700-1400 euros kW _e^-1 in the future (Faijj 2006). Pyrolysis plant are even more expensive, with current estimates of installation costs for a 10 MW plant being £4,400 kWh ^-1 ( RCEP 2004).

Few studies exist that comparatively assess the capital and O&M costs of biomass systems with other renewable technologies. A study by OXERA (2004) for DTI suggested 'average' values for plant economics of different renewable technologies, as shown in Table 6.9. Both 'average' fixed and O&M costs for energy crop plant were estimated to be higher than onshore and offshore wind, but less expensive than marine. The OXERA values are generally lower (except for wind) than values recently published in a report by PB Power (2006), where capital costs for a biomass bubbling fluidized bed combustion plant are quoted to be £1,744 kW ^-1 and tidal technology capital costs are quoted as being £2,200 kW ^-1. This is in sharp contrast to the capital costs of onshore wind (£824 kW ^-1) and substantially higher than coal and gas technologies (£340 - 1,000 kW ^-1).

Renewable energy technologies, on the whole, are capital-intensive. The capital costs of onshore wind project, for example, correspond to 75-90% of the total costs ( BWEA 2005). It is necessary to emphasize, however, that the costs given in Table 6.6 must be taken to be purely illustrative, as costs are variable and continuous technological developments have the effect of lowering costs. Variability in capital costs can be brought about by such factors as site-specific infrastructure requirements, the duration of the construction period and price variations in equipment due to shifting supply and demand patterns ( RAE 2006).

Table 6.9 Illustrative Costs of Different Renewable Electricity Technologies

Source: OXERA 2004

Rates of Return

The Carbon Trust (2005) considered the economics of large biomass-fuelled electricity, CHP and heat plant, over a range of plant scales and under 3 scenarios: 1) current government incentives and crude oil price of $30 a barrel, 2) no government incentives and crude oil price of $30 a barrel and 3) no government incentives and crude oil price of $50 a barrel. As shown in Table 6.10, the internal rates of return ( IRR) for all of these plant types was found to be very negative without government incentives at an oil price of $30 per barrel. At an oil price of $50 per barrel, large CHP provides positive rates of return, but the overall picture for dedicated electricity plant and small CHP was still negative.

Table 6.10: Internal Rates of Return of Different Bioenergy Technologies Under Three Scenarios

Source: The Carbon Trust (2005)

With current oil prices standing at well over those included in the Carbon Trust report, more positive returns would be expected. With regards to individual feedstock chains, the Carbon Trust found that utilization of wood wastes and agricultural residues was more cost-effective than energy crop and forestry product chains, which is a reflection of the cheaper costs of those fuels. In some cases, such as small CHP and large electricity (under the scenario with current government incentives and oil price of $30 per barrel), the feedstock utilised determined whether the plant had negative or positive return rates, although the economic margins remained low.

6.3.4 Delivered Electricity Costs

Electricity generation costs provide an additional means of comparison between technologies, provided the comparison is transparently carried out in a like-for-like basis. This is often difficult when drawing on the results of different studies, as are these are complicated by a raft of interacting variables, among which market mechanisms, subsidies and transmission and distribution costs can be highlighted ( RAE 2004, PB Power 2006). Like-for-like studies from which policy makers can derive meaningful conclusions are exceedingly rare in the available body of literature. A study by PB Power for the Royal Academy of Engineers originally published in 2004 but reviewed in 2006, is one of the few examples where this has been attempted. The revised study used actual data on the construction, maintenance and running of power plants and applied an even discount rate to all of them (10%).

Figure 6.4: E lectricity Generation Costs for Renewable and Fossil Technologies

Source: PB Power (2006). Generation costs include capital and equipment cost, fuel costs, and O&M costs. Does not include revenue associated with support mechanisms such as ROCs. Biomass refers to BFB combustion of forestry residues at a price of £25 odt ^-1.

The results (in p kWh ^-1) are shown in Figure 6.4. At present, coal pulverised fuel and circulating fluidized bed combustion technologies are the most cost-effective, while onshore wind is by far the most cost-effective renewable electricity generating technology. As an electricity producing option, biomass is considerably more expensive than all the currently commercial technologies and is similar in price to offshore wind. In the absence of additional support mechanisms such as ROCs, biomass electricity is therefore not competitive at present.

Other 'default' data on electricity generation costs or costs of delivered electricity are available in the literature, but the underlying calculations are not always transparent. For example, Dawson et al. (2005) provided electricity generation costs for a range of wood fuels according to combustion and gasification systems of varying sizes. In like-for-like boilers, as would be expected, electricity generation costs of residues were found to be lower than those from more expensive biomass sources such as wood pellet. The higher efficiency of gasifier CHP systems was found to result in lower cost generation relative to steam cycle turbines, as would also be expected.

A Note on Co-firing Economics

Less information is available on the economics of co-firing than for other biomass end-uses. Nevertheless, there are increased costs associated with biomass fuels over coal (see section on fuel costs) and extra processing costs that need to be borne, so that co-firing is not a competitive option without a system of incentives in place such as the ROC system. The ROC system does present economic benefits to the plant, although these are insufficient to change the overall operational regime of the plant for strict biomass firing (Hotchkiss et al. 2002). It is reasonable to affirm that the economics of co-firing is closely linked with the costs of the fuel. It is no surprise that most of the fuels co-fired to date have been residues obtained at low cost. The Renewables Obligation Scheme dictates, however, that increasing proportion of co-fired biomass must come from purpose-grown energy crops, which are significantly more expensive than residues, although these rules are currently under review. Detailed economics studies on co-firing with energy crops were not found.

A Note on Anaerobic Digestion Economics

The economics of anaerobic digester ( AD) systems is influenced by a range of factors, including the scale, cost of existing waste treatment, conventional energy source being replaced and transportation costs of manure. Invariably AD plants are characterized by large capital costs (Towers et al. 2004). Mullan (2005) carried out an economic appraisal of a centralised AD plant in Ireland and calculated that a sizeable net profit was possible with ROC awards and assuming sales of both power and heat output. Under the assumptions of the study, the price of producing electricity from biogas was 6.6p kWh ^-1, which was still slightly cheaper than generation from wood fuels. Farm-scale projects, however, are not generally cost-effective if viewed from the perspective of electricity production. The environmental benefits of anaerobic digesters must also be taken into account, however. The Scottish-Executive supported biogas plants in Southwest Scotland, for example, that were funded to investigate the benefits biogas production from cattle slurry might bring to the reduction of faecal indicator organisms in bathing waters, by reducing diffuse pollution from agriculture (Chesshire 2005) and such benefits need also be considered in the economic analysis. The plants in the Southwest of Scotland are only operating at 25% capacity and there are obviously economic benefits that could accrue from greater exploitation of the capacity of the plants.

There may also be opportunities for co-digestion with other feedstocks such as energy crops and trials are under way in this respect (Southern Uplands Partnership 2005).

6.3.5 Carbon Abatement Costs

The Carbon Trust Biomass Sector Review (2005) also presented information on the carbon abatement costs of CHP and dedicated bioelectricity plant of various sizes. The results of the report for electricity/ CHP are shown in Table 6.11. The benefits of economies of scale are evident as large CHP was found to have intermediate carbon abatement costs of £90-130 tC ^-1, within the social carbon cost range suggested by the government (£35-140 tC ^-1), while large electricity and small CHP had considerably higher abatement costs at £215-300/tC. From a carbon cost point of view, small electricity schemes are not viable at the moment as they require carbon abatement costs of £587-639 tC ^-1. The few other studies that have indicated carbon abatement costs support these results. The Lek Report for DTI (2004), for example, estimated that the carbon mitigation cost of electricity generation from SRC in a 10 MW_e plant was £281 tC ^-1.

Table 6.11: Illustrative Carbon Abatement Costs of Different Biomass Electricity/ CHP Technologies

Source: Carbon Trust (2005). Assumes crude oil price @ $30/barrel, without government incentives.

Carbon abatement costs for a range of renewable energy technologies with gas-fired generation as a baseline were estimated by Oxford Research Associates ( OXERA) for the year 2020. The results of the study, which used compared carbon abatement costs at four different gas generation costs, are provided in Table 6.12.

The OXERA (2004) results indicate that the carbon abatement costs of electricity from energy crops in 2020 will be higher than both onshore and offshore wind, comparable to marine and cheaper than photovoltaics. The carbon abatement costs depend ultimately on the carbon balances of the individual energy system being considered and on the costs associated with each technology. The above table demonstrates clearly the effect of the technology costs on the carbon abatement costs, as it mirrors closely the electricity generation costs associated with the renewable energy technologies and effect of fossil fuel prices (Table 6.8).

Table 6.12: Illustrative Carbon Abatement Costs in 2020 for Different Renewable Technologies

As discussed in Chapter 4, the carbon balance of a particular system is highly context-specific, being affected by the transportation distances involved, the harvesting procedures utilized and scale of the operation in question. Hence, generic results such as those provided above, whilst providing a general basis for comparison, can not represent the full variability possible for a particular technology such as electricity production from energy crops.

6.3.6 Market Prospects

Market Opportunities

There is an ongoing debate about the individual future roles of electricity and heat in the development of the biomass energy sector in Scotland (see for example, the evidence gathered during the course of the Scottish Parliament Biomass Inquiry available at www.scottish.parliament.uk). Due to the lower efficiencies of electrical generation, utilization of biomass for electricity is a more inefficient use of the resource than for heat (or CHP) and, indeed, the prevailing opinion at present is that the expansion of smaller localized heat networks would bring greater benefits than the establishment of a small number of large-scale electricity generators (see oral evidence to Scottish Parliament Biomass Inquiry 2006). Nonetheless, large-scale biomass power will play a role in the development of the sector, as evidenced by the beginning of construction work on the 44 MW_eEON plant in Lockerbie, which will utilize both wood from forestry sources and also short rotation coppice. Plans are also underway for the development of a 50 MWe CHP unit in Glenrothes, which will integrated with the Tullis Russell paper mill, supplying the heat and electricity needed by the mill and exporting the surplus electricity to the grid. The EON plant is due to start operation in late 2007, while the Tullis Russel plant has obtained planning permission and has been offered a firm grid connection for 2008 (Scottish Coal 2006). If both plants are to become operational, they would account for roughly 600,000 odt yr ^-1 of wood fuel, a sizeable proportion of Scotland's total resource. There are other potential developments which are currently in a scoping stage, including the Invergordon Forscot plant, which if developed would consume a third of Scotland's total roundwood harvest (Reference Consultants 2006).

There are fears that such large electricity/ CHP schemes could result in a 'demand shock' where excessive volumes of biomass resource are required before an adequate supply infrastructure is developed (Oral Evidence to Scottish Biomass Inquiry 2006). Moreover, the nature of Scotland's dispersed forestry resource means that transportation costs would be high for centralised electricity production plant, which would bring the undesirable consequence of increased emissions. There is also an argument, however, for smaller scale biopower/ CHP units (1-2 MW_e) in that they could help to cement local woodfuel supply chains by forming the focal points of 'supply clusters'. But, as shown in the Carbon Trust report, the economic case for these is not strong.

Employment Opportunities

The SDC report (2005) estimated that 1.5 jobs MW_e^-1 could be created by developing a co-firing fuel supply chain and that another 3 jobs could be created at the power plant as a result. Similar estimates were made for dedicated power from biomass, where 1.5 jobs MW_e^-1 could be created by development of the fuel supply chain and 2-4 jobs MW_e^-1 could be created at the plant.

Further generic estimates of biomass industry impact on the job market were made in DTI Renewables Gap Analysis report, which suggested that 19-25 jobs MW_e^-1 could be created by the development of the bioelectricity industry, subdivided into .5 jobs for development, 15-20 for the construction phase and 3.5-4.5 for operational phase (Figure 6.5). These figures are similar to the SDC figures if the construction component is removed. As far as employment is concerned, biomass is at an advantage to other renewables as a fuel supply chain is required, creating an extra employment dimension not possible with non-fuel renewables such as wind and tidal.

Figure 6.5: Illustrative Employment Benefits (jobs MW_e^-1) of Different Renewable Technologies.

Source: DTI 2004

6.3.7 Grants and Incentives

The renewable electricity sector in Scotland has been boosted considerably by the introduction of the Renewable Obligation (Scotland), which came into force in April 2002. The scheme requires that all electricity supply companies provide an increasing proportion of their electricity from renewable sources. Electricity from biomass and also co-firing forms part of the portfolio of renewable technologies that can claim renewable obligation certificates ( ROCs). The scheme is currently under review and there a number of proposed alterations that may boost the use of biomass for CHP and biopower. These include a reduction in the 'purity' of biomass eligible for ROCs from 98% to 90% and thus encourage the use of recycled timber and efforts to facilitate ROCs being gained by local production of electricity, not exported to the grid.

Several grants are available that promote the development of bioelectricity sector, each one varying in scope and targeting particular aspects of the industry. One of the main incentives is the Bioenergy Capital Grants Scheme, which is now closed to new applications for large-scale CHP/electricity plant, but has recently announced a round of applications for small heat and CHP plant. This grant was a major funding source for the EON plant in Lockerbie. Other grants are available that promote the production of energy crops or the strengthening of fuel supply chains. These are described in more detail in Annex 5. The list does not include grants for research.

Anaerobic Digestion

Few studies were found which identified the potential for the development of anaerobic digestion and impacts on employment generation. Anaerobic digestion units meet objectives which are not related exclusively to greenhouse gas mitigation or energy provision and these environmental drivers may propel the industry, as has occurred in some European countries. As mentioned in section 6.2.3, there are currently seven trial plants sponsored by the Scottish Executive in the southwest of Scotland. Whereas these small-scale farms are unlikely to create many new jobs, larger centralised plants such as the Holsworthy Plant in Devon have greater potential to do so (Farmatic 2004). A study into the feasibility of such a plant in Scotland is very desirable.

Co-firing

Opportunities for co-firing in Scotland are limited in the sense that there are only two coal-fired power plants, but jointly these have an installed capacity of 3600 MW_e. A 10% share of this output would be similar in magnitude, therefore, to the combined output of 10-12 large (30-40 MW_e) CHP units. Co-firing is commonly seen as a means of kick-starting a wider fuel supply chain for biomass heat and CHP development ( RCEP 2004). This is especially true for short-rotation coppice, as current co-firing rules require power plants to use increasing amounts of purpose-grown energy crops, although these are currently under review. At present, co-firing is largely supplied with imported fibre.

6.3.8 Relevance of Literature Coverage to Scotland

The values for energy crop gross profit margins depend critically on the yield of the crops and the level of financial incentives provided. Current experimental work suggests that yields of SRC coppice in Scotland do not differ significantly from those in England and Wales (Forestry Commission 2005), although miscanthus appears not to perform so well under Scottish conditions. With regards to governmental support, a £1000 ha ^-1 one-off establishment grant for SRC willow was recently announced (Ogilvie 2005), which is similar to the price for non-set aside land payments in England and Wales. Scotland's large wood fuel resource may mean that energy crops may not become a significant renewable energy source in the near future, but could become so if higher C reduction targets are set and if current co-firing rules which require an increasing proportion of energy crops are maintained. The fact that their production can be expanded quickly gives them an advantage over agricultural and forestry residues, which are predominantly offshoots of other industries.

The main studies on plant economics, rates of return and carbon abatement costs have produced generic results on a UK level. More reliable Scotland-specific studies are perhaps not achievable at present as the market of biomass for electricity/ CHP is new and it is not possible to predict with accuracy what the main fuel chains/plant sizes will be. Nevertheless, studies that simulate the economics of different development scenarios ( e.g. varying mixes of heat/electricity operating at different scales) would be particularly useful, as the particularities of the systems in question can make a big difference to economic functions such as carbon abatement costs.

6.4 Transport Biofuels

6.4.1 Production Costs

Oilseed Rape for Biodiesel

Up to the mid-1990's, oilseed rape benefited from additional EU area payments which encouraged its production. However, the reform of the common agricultural payment ( CAP) meant that such payments were abandoned and the returns of oilseed rape must compete directly with other crops (Booth et al. 2005). As shown in Table 6.13, the gross margin of winter oilseed rape in Scotland is currently well below that of the major cereal crops. Although seed prices are the same (£140 t ^-1), the gross margin of spring oilseed rape is lower than that of winter oilseed rape due to lower yields. The difference in relationship to cereals is mainly due to the additional income that can be obtained by selling the straw, which can yield £100-140 ha ^-1, depending on the cereal crop. As rape straw currently has no commercial value, it does not increase the gross margin, although its utilization for energy could lead to additional financial benefits for the farmer.

Although oilseed rape may appear to be an unfavourable economic option after analysis of gross profit margins, it has many advantages, including its use as a break crop for cereal production, enhanced wheat yields following its use in rotation and reduced nitrogen requirements for subsequent cereal crop (Booth et al. 2005). Oilseed rape brings benefits, therefore, that gross margins can not capture.

Table 6.13: Gross Margins of Oilseed Rape vs. Cereals in Scotland ( £ ha ^-1 yr ^-1) - 2006 harvest

Source: Booth et al. (2005). Based on seed prices of £140 t ^-1 for OSR, £80 t ^-1 for spring barley and £74 t ^-1 for wheat and straw prices of £20 t ^-1 for wheat and £25 t ^-1 for winter barley.

Bioethanol Feedstocks

Wheat, barley and potatoes have been suggested as being the main bioethanol feedstocks of relevance to Scotland, given the improbability of the resurgence of sugar beet production (Booth et al. 2005). The gross margin of wheat and barley is given in Table 6.3, with wheat and winter barley both providing an income of over £700 ha ^-1 yr ^-1. The gross margin of potatoes, due to the extraordinarily high yields that are achievable, can be over £1500 ha yr ^-1. As mentioned in Chapter 3, almost all of Scotland's potato crop is high-quality stock produced for food purposes and the gross profit margin reflects this. As potatoes have never been used for bioethanol production in the UK, there are no current estimates of gross profit margin for this end-use, as is also true for wheat and barley.

6.4.2 Fuel Costs

The production costs of transport biofuels are about twice that of mineral transport fuels (Turley et al. 2003, Booth et al. 2005), although the higher prices of oil mean that this differential is falling. This higher cost is partially offset by a 20p l ^-1 rebate on fuel excise duty for biodiesel and bioethanol, although this doesn't apply to crude vegetable oil. Biodiesel and mineral diesel production costs and final pump prices are shown in Table 6.14a, while bioethanol pump prices are shown in Table 6.14b.

Table 6.14a: Diesel/Biodiesel Pump Prices in the UK, Dec 2004

Source: Booth et al. (2005b), taken from HGCA.

Table 6.14b: Petrol/Bioethanol Pump Prices in the UK, Dec 2004

Source: Billins (2005b), taken from HGCA.

The figures in the table are true for late 2004 and have changed, with pump prices for petrol approaching £1/L. The biodiesel price relates to production from rapeseed and will be cheaper than this from tallow due to cheaper feedstock price. Scottish-specific data on these costs should be available from Argent Energy, but these could not be obtained in time to include in this report. A recent review by IFEU (2004) came to the overall conclusion, however, that there was no clear difference in price between biofuels produced from residues and biofuels produced from cultivated biomass although a broad generalization was not possible due to the extremely wide spectrum of production costs covered in the report.

6.4.3 Plant Economics

Current Transport Fuels

Biodiesel

Scale of operation is crucial to the economics of biodiesel plants (Table 6.15). Biodiesel production from tallow and used vegetable oils has already begun at the Argent Plant in Motherwell, set up in 2004 to produce 50,000 t of biodiesel annually, requiring a capital investment of £15 million. To produce biodiesel from rapeseed oil, the crushing plant represents a large additional cost that must be met either by the biodiesel producing plant itself or by an associated business initiative.

A full evaluation of the economic feasibility of oilseed rape production in Northeast Scotland, including five different production scenarios, was recently carried out by experts from the Scottish Agricultural College (Booth et al. 2005). The results are shown in Table 6.15.

Booth et al. (2005) carried out a further economic appraisal of the medium-scale industrial plant and calculated that an increase in biodiesel price of 2 pence (from 41p l ^-1 to 43p l ^-1) was sufficient to increase the internal rate of return from 14.1% to 23.5% and consequently decrease the payback time from 5 years to 4 years. The study concluded that a medium-scale plant was viable in Scotland, but that there were considerable inherent risks involved which could be best mitigated by the formation of a joint venture company involving the relevant members of the production chain (farmers cooperative, processing business, regional fuels distributor, etc.)

The market for the by-products produced can make an important contribution to the viability of the plant (Booth et al. 2005b). In the case of biodiesel these are rapemeal and glycerine. Booth et al. (2005b) report that in 2005, the average price of rapemeal was £90/tonne and that the estimated demand for the product in Scotland was 30,000 - 40,000 t yr ^-1. In some regions, such as Lower Saxony in Germany, rape cake has begun to be used in co-firing at coal power stations, thus providing and economic means of obtaining a more positive carbon balance. (Hoher 2005). Glycerine has a wide range of existing markets and in 2005 its value was estimated as being approximately £110/tonne. However, due to the lower volume produced, glycerine will not have as high an effect on the economic viability of the plant as rapemeal (Booth et al. 2005b).

Table 6.15: Illustrative Economics of Different Scales of Biodiesel Production in Scotland.

Source: Booth et al. 2005

Bioethanol

Although there are currently no bioethanol plants operating on a commercial scale in the UK, there are two under development. Wessex Grain has been granted permission to build the UK's first bioethanol from wheat plant in Henstridge, Somerset, which will produce 100,000 tonnes of bioethanol annually once operational. Capital costs are estimated to be in the region of £40 million and production costs at around 35 p/L (Wessex Grain 2005). British Sugar have already begun the construction of a sugar beet bioethanol plant at Wissington, Suffolk (British Sugar 2006). The plant will produce 55,000 tonnes of bioethanol a year, with capital costs of about £20 million. The detailed economic evaluation carried out for biodiesel in Scotland have not been extended to bioethanol and the current body of opinion is that there is much less opportunity for bioethanol production in Scotland than biodiesel. This is due to the availability of cheap imports that could disrupt the market and to the fact that Scotland does not face a petrol deficit in the way it faces a diesel deficit (Booth et al. 2005, see also Chapter 3).

A Note on Future Transport Fuels

Transport technologies such as ethanol production from lignocellulosics, hydrogen production from gasification of biomass and FT diesel production from gasification of biomass are expected to provide excellent greenhouse gas benefits in the intermediate to long-term future. As these technologies are still in research and development stages, accurate estimates of their production costs are not possible at present, although several estimates of future costs are available in the literature. Table 6.16 gives estimated costs as provided by Faijj (2006). It must be borne in mind that these costs are indicative at best and have been gathered from a range of dispersed sources, which often utilize different underlying assumptions.

Table 6.16 Comparison of Plant Economics of Future Transport Fuel Production Technologies

Source: Faijj (2006)

6.4.4 Market Prospects

The potential of biodiesel production from rapeseed in meeting Scotland's renewable transport fuel obligation was clearly demonstrated in the report by Booth et al (2005). Among home-grown biofuel feedstock options, this appears to be the only one that would make true economic sense, given the absence of a sugar beet industry in Scotland and the excessive costs associated with producing ethanol from wheat and potatoes, Scotland's other possible bioethanol feedstocks. Furthermore, there are sugar beet-growing areas south of the border which may be better suited to develop a bioethanol industry.

Employment Opportunities

The development of transport biofuel industry is likely to have a positive effect on employment in Scotland. Growing crops on set-aside land can generate additional jobs in agriculture as crop production requires more labour than maintaining land in set-aside. It is estimated that a 100,000 tonnes biodiesel plant could creates jobs for 62 staff while a bioethanol plant of a similar size could create jobs for 50-55 people, with an additional 16-28 jobs being created in blending and transport (Turley et al. 2003). This is likely to reflect positively on the wider economics of associated UK industries, as a greater share of the costs are retained in the UK, with bioethanol (91%) and biodiesel (95%) compared to gasoline and diesel (82%) (Turley et al. 2003).

6.4.5 Grants and Incentives

The main driver for the development of a competitive transport biofuel industry in Scotland is the Renewable Transport Fuel Obligation ( RTFO), announced at the end of 2005, which obliges suppliers to provide 5% of their final transport fuel from renewable sources by 2010 and is proposed to start in 2008. Interim targets for the RTFO have been set for 2.5% in 2008-2009 and 3.75% for 2009-2010 ( HM Treasury 2006). This legally binding instrument will move the renewable transport fuel sector into a completely different gear.

Thus far, the main government financial incentive for transport biofuels has been the reduced excise duty in relation to mineral diesel and petrol of 20 p/l (27.1 p vs. 47.1p). A continuation of this excise duty was recently announced in the national budget for 2006 ( HM Treasury 2006). This level of rebate is still significantly lower than the level of support offered in other European countries. In Germany, for example, all biofuels have been exempted from tax until 2009 (Henke et al. 2005), which has permitted extremely rapid development the transport biofuel industry in that country.

6.4.6 Relevance of Literature Coverage to Scotland

The study by Booth et al. (2005b) provided an excellent evaluation of many facets of the economics of biodiesel from rapeseed production in Scotland, including a full evaluation of different possible future scenarios. No studies were found investigating the potential and economics of bioethanol production in Scotland.

6.5 Further Issues Related to the Economics of Biomass Energy Options

6.5.1 EU Incentives

CAP Reform

The reformed CAP and the single payments scheme adds a dimension of flexibility to agricultural production systems that should facilitate the uptake of bioenergy crops as emphasis is shifted away from the production of food crops. The decoupling of subsidies for cereal production is expected to decrease cereal production as farmers choose to plant the crops that allow them to compete successfully on an open market. How the reformed CAP will affect plantation of bioenergy crops therefore is essentially a question of economics. In 2004, the high production costs of cereals and low prices paid for the crop led to unfavourable net margins for wheat and barley ( SEERAD 2005). Extension of this trend could increase the likelihood for producers to take up energy crop plantation. The CAP also offers a direct incentive by paying an establishment grant of 45 Euros ha ^-1 for energy crops (except sugar beet) grown on non set-aside land, but this is restricted to a total hectarage of 1,500,000 ha across Europe.

There is an argument, however, that the single farm payment scheme associated with CAP may not promote the uptake of energy crops as might be expected in Scotland. According to the Highland Council (2006), the requirement of the single farm payment scheme that the land be kept in good agricultural and environmental condition has in some cases resulted in decreased farm activity, especially in cases of farmers who have the best land and receive the highest single farm payments.

Structural Funds

Structural funds are the main source of EU funding in Scotland, providing over £ 1.1 billion pounds for the period 2000-2006 (Scottish Executive 2006). The main aim of these funds is to promote sustainable economic development in regions of the EU that are in decline, thus reducing regional disparities. There is a growing body of opinion that structural funds could be used to mobilise the large capital investments needed for developing biomass supply chains and adding momentum to the bioenergy sector (see for example, WWF 2006). In some countries, structural funds have already been applied in bioenergy projects. In Wales, for example, EU structural funds were invested in a demonstration project to develop sustainable heat and power from short rotation willow ( http://www.iger.bbsrc.ac.uk/Willow/welcome.htm).

The next round of EU structural fund programmes will begin in 2007 ( DTI 2006). The Highlands and Islands will qualify for a 'phasing-out convergence fund' as they have a GDP below 75% of the EU-15 average but above 75% of the EU-25 average. This is, in essence, a transitional support for regions that would have qualified for the full convergence funding if the EU had not been enlarged to 25 States, equating to approximately 60% of what the region currently receives. The lowlands and uplands of Scotland will be eligible for funding under the competitiveness objective over this period. The European Council has agreed a total EU budget of £575 billion for the UK for 2007-2013. This budget was expected to have been submitted to Parliament by Easter 2006. The remaining Scottish regions outside the Highlands and Islands could receive up to 45% of what is received under the current regime, but this depends on an agreement within the UK over how to divide the funds (Scottish Executive 2006b).

The development of the biomass energy industry would appear to be completely compatible with the main priority areas outlined for ERDF spending within the Highlands and Islands Convergence Programme of economic sustainability, community sustainability and environmental sustainability ( DTI 2006). The same can be said of the priorities for ERDF spending under the competitiveness and employment objectives which are: 1) supporting innovation and entrepreneurship, 2) promoting community regeneration and 3) environmental sustainability and rural development. Further work on how structural funds could be employed in the development of the biomass energy industry is merited.

6.5.2 International Emissions Trading Schemes

EU and UKETS

The European Union Emissions Trading Scheme ( EUETS) is world's largest scheme of its kind and is currently in its first phase of implementation, which includes lower penalties for non-compliance and a provisional opt-out mechanism that will not be included in the second phase of the scheme. Only generators with a minimum 20 MW_th output qualify for the scheme through the National Allocation Plan ( NAP) and non-thermal renewable technologies such as wind and wave are excluded. The scheme, which in Scotland is regulated by SEPA, distinguishes between those plants built before December 31, 2003 and those built after with only the latter qualifying for a free allocation of allowances under the New Entry Reserve (Smartest Energy 2005) The scheme also rewards fossil fuel plants that convert to biomass. In total, over 100 Scottish institutions are registered in the first phase NAP, which together account for approximately 50% of Scotland's CO₂ emissions. The National Allocation Plan for phase II of the EUETS is currently under consultation. An analogous UK-wide scheme, the UKETS, is also functional. This scheme operates separately to the EUETS and differs from its European counterpart scheme in three ways: 1) the UKETS is voluntary whereas the EUETS is mandatory, 2) in the EUETS, emissions from electricity generation are assigned to the electricity generators while in the UKETS, they are assigned to the end-users and 3) the EUETS focuses predominantly on sectors covered by the IPPC directive whereas the UKETS is more economy-wide (Defra 2005).

Although the EUETS will help to incentivise the uptake of biomass in Scotland, it could also stimulate competition for Scotland's available biomass resource and may disproportionately favour large-scale schemes to the detriment of smaller-scale heat initiatives, for example. Although the EUETS is expected to increase power prices, the overall impacts on the economics of new biomass developments is likely to be less significant than the impact of ROCs due to uncertainty in long-term prices of carbon (Smartest Energy 2005).

Kyoto Protocol

The Kyoto Protocol offers a variety of flexibility instruments including the Clean Development Mechnanism ( CDM) and Joint Implementation ( JI) schemes. Such projects offer the opportunity to tie in production of energy from biomass with carbon sequestration projects. The Clean Development Mechanism allows for developed countries to meet their Kyoto targets by implementing greenhouse gas mitigation projects in developing countries. This allows for renewable energy technologies to be transferred to developing countries, for example. The CDM dictates that carbon credits can be obtained by projects where baseline emissions of fossil fuels are reduced or eliminated. For many developing countries, this represents a problem in that fossil fuel systems are not readily accessible and funding for CDM is therefore not available (Schlamadinger and Jurgens 2004). Joint implementation schemes allow Annex 1 countries to meet their Kyoto targets by participating in projects with other Annex 1 countries to generate emission reduction credits which can then be sold on the international emissions market.

6.5.3 Carbon Mitigation Economics

Substitution of fossil fuel carbon through increased uptake of renewable energy sources, including biomass, is one of a range of options to combat climate change, including afforestation and long-term carbon storage in wood products and reduction in greenhouse gas emissions from other sectors. For bioenergy feedstocks, it is important to note that growing trees (and short rotation coppice) add to carbon savings through terrestrial carbon sinks prior to their use for bioenergy. However, direct comparison of the cost-effectiveness of different mitigation measures (through biomass production and consumption and beyond) is made difficult by the fact that there are differences, for instance, in the permanence of the C-offset associated with them. Whereas GHG emission reduction and substitution of fossil fuels with biomass offer infinite carbon savings, forest plantations reduce atmospheric CO₂,,as long as there is net growth. If properly managed, forests act as a carbon sink (Nijnik 2005). With the decay of forest material, however, carbon is lost. Using wood for energy is by itself also a C neutral process, because when wood is used for energy, carbon stored in biomass is released as CO₂ upon burning. The most important net gain in this case is the amount of CO₂ that would have been released by burning fossil fuel, had it not been replaced by wood. Estimation of benchmarks, such as present value costs per tonne of C savings under different mitigation strategies, are required for Scotland.

Van Kooten et al. (2004) performed a meta-analysis of studies that estimated the costs associated with establishing forest sinks. The study identified a huge variability in estimated costs, depends on the carbon accounting methodology employed. Under baseline conditions of forest conservation for carbon sequestration, costs were found to range from US $ 46 - 260/tC. When opportunity costs were taken into account, the cost range increased to US $117-1400 /tC. Additionally, peer review was found to increase costs by a factor of 10. The conclusion, therefore, is that even though carbon sinks are often presented as low-cost alternatives to fuel switching, it is very difficult to directly compare the costs of the different options involved.

Very few studies exist in Scotland on this topic and it is an area that merits further attention, as comparative indicators of the cost-effectiveness of alternative mitigation strategies are needed. This kind of work has been carried out in other countries (Nijnik 2005).and could be modified for Scottish conditions.

6.5.4 Externalities and Hidden Costs

Externalities are 'changes of welfare generated by a given activity without being reflected in market prices' (di Valdalbero 2006). The production of electricity, heat or transport fuel has several effects on society and the environment which could be considered externalities. As discussed in chapter 5, there may be acidification and eutrophication impacts as well as impacts on human health which may arise from energy production in addition to increased impacts on global warming that arise from increased fossil fuel use.

If taken into consideration, these external costs may help to move towards a more sustainable energy production system. Biomass may play an important part in reducing these external costs, especially through the greenhouse gas benefits incurred. Assigning financial values to these costs is not easy, but has been attempted on a number of occasions. The Extern E (1998) study used a modelling approach to estimate the external costs of damage caused by major air pollutants in the European Union. The results of the study were that the damages of NO₂ emitted cost between 2.4-2.9 €/kg NO₂, while SO₂ damages were in the 2.9-3.5 €/kg SO₂ range. More recent figures suggest an even higher cost of damages caused by these pollutants (di Valdalbero 2006 - Table 6.17)

Some countries, notably Sweden, have already developed taxes for the emission of these air pollutants which is levied on fossil fuels used for heat production (Karlsson and Gustavsson 2003). Such taxes can greatly favour the uptake of one form of energy generation over another and could confer a competitive advantage to biomass, although this depends on the relative emissions of biomass fuels to fossil fuels (Chapter 5).

Table 6.17: Illustrative Economic Damages of Air Pollutants in the EU (€/tonne)

6.5.5 Social Issues

Reduction of Fuel Poverty

In 2002, fuel poverty affected 13% of Scottish households (Scottish Executive 2006). Great advances have been made in tackling this problem mainly as a result of the Warm Deal and Central Heating Programmes which together helped to halve fuel poverty in Scotland between 1996 and 2002. Concurrent with plans to extend these initiatives, the Scottish Executive has announced plans to run a pilot study to explore the potential of renewable energy technologies for domestic heat production. Wood fuel is well placed to contribute to these objectives as has been shown in the establishment of wood chip district heating schemes for social housing projects and other domestic heating systems installed with assistance from the SCHRI.

Employment Opportunities

From a social perspective, biomass energy can provide a range of benefits providing new jobs and training opportunities. Especially with the development of localized wood fuel supply chains for small-scale heat units, biomass can help promote rural development and reduce urban drift. Local bioenergy production can bring with it a wealth of benefits besides the creation of jobs, as summarized in Table 6.18. The table is based on work carried out in an international project to evaluate the socio-economic aspects of bioenergy systems (Domac et al. 2005).

Table 6.18: Benefits Associated with Local Bioenergy Production

Source: Domac et al. 2005

6.6 Economics Conclusions and Recommendations

With regards to the general economics of biomass energy systems for Scotland, several broad-level conclusions can be made:

• The literature does not present a convincing case for the economics of energy crops and these appear to be economically feasible only under set-aside land at moderate to high yields.
• Heat production on the whole is much more economically sound than electricity production and small-scale heat, in particular, seems to provide the best returns.
• The carbon abatement costs of biomass heat systems are much lower than those of biomass electricity systems. In addition, the carbon abatement costs of biomass heat systems are much lower than those of alternative renewable heat technologies.
• The carbon abatement costs of transport biofuels are high in comparison to other technologies.
• Biomass provides excellent prospects in terms of creating new jobs.

Several areas where further studies would be beneficial have also been highlighted:

• Comparative studies of different renewable technologies with regards to electricity generation costs and carbon abatement costs should be encouraged, as there is surprising little transparent data available in the literature.
• Integrated life cycle analysis and economic studies of the biomass chains which are likely to be of greatest relevance to Scotland are encouraged for different biomass uptake scenarios involving different allocations for heat and electricity schemes of various scales. Such a study would provide data on economics aspects such as carbon abatement costs which are specific to Scottish conditions.
• A comparative study of the economics of alternative carbon sequestration schemes of relevance to Scotland ( e.g. bioenergy production vs. carbon sequestration through afforestation) would be very informative, provided it is carried out in a structured and transparent manner.

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