Study of the economics of example CHP schemes

Study of the economics of example CHP schemes July 04 Executive Summary As part of the strategy to meet the carbon emissions reduction targets required under the Kyoto Protocol, the U.K. Government has recognised the importance of Combined Heat and Power (CHP) as one of the key economically viable technologies to help in achieve this. In November 2000, the CHPQA Programme was introduced to assess the quality of installed CHP plant, and the concept of Good Quality CHP was launched. In May 2002 a public consultation document was published outlining a draft CHP strategy to 2010 for the U.K. The Government has a target to reach 10 GWe of Good Quality CHP capacity by 2010. The installed capacity in 2002 was around 5 GWe and it is estimated that there is another 1 GWe of CHP capacity already under development or accessible through the increased use of heat at existing schemes. This leaves around 4 GWe additional capacity needed to meet the target. As part of the CHP strategy development, Cambridge Econometrics undertook a study to project CHP1 capacity by 2010 under a variety of policy scenarios. A model was produced that projected economic CHP potential in the U.K., based upon a top-down analysis using representative values for CHP schemes. Defra subsequently commissioned Future Energy Solutions to undertake a complementary bottom-up analysis of CHP economic potential using data from real sites. The effect of policy measures upon CHP potential, both fiscal and in the form of an obligation was assessed in this latter study. The results are presented in this report and compared, where possible with those from the earlier Cambridge Economics study. The potential sites for this bottom-up study were chosen to ensure, as far as possible, that the sample was a cross-section of typical industrial and commercial installations with technical potential. Contact was made with the site operators or developers to: • • Obtain qualitative information on the state of the market and any factors of particular importance to their schemes. Obtain quantitative information, particularly economic data, on individual schemes. In general, most sites were willing to provide qualitative information. Obtaining quantitative information was more difficult, partly because of concerns regarding commercial sensitivity and confidentiality of the data and partly because of resource limitations on the part of the operators/developers. Modelling of the economics for 14 individual sites was carried out to calculate the financial returns for each potential scheme for a variety of scenarios. The modelled sites have a technical potential of about 400MWe of installed CHP capacity. The criteria used to assess the economic viability of sites was discussed with the operators/developers and it was decided that a CHP scheme would require to have an Internal Rates of Return (IRR) of around 15%, calculated over a 15 year period, to be commercially viable in the current uncertain market. A lower IRR could be considered economic if the energy market stabilised. 1 Within this report, all references to CHP refer to ‘Good Quality’ CHP and are to be read as such. AEA Technology ii It has been suggested to us that the high degree of instability in gas and electricity prices makes forecasting future savings from CHP plant too uncertain for many developers to reenter the market and that long-term ‘bankable benefits’ are needed to promote new CHP development. Where there is inherent uncertainty, e.g. in a measure such as the EU-ETS, there will be some discounting of its value in an investment decision. Never the less, even in current market conditions, some small-scale CHP schemes are economic and can provide attractive returns on investment. The analysis presented here looks at individual scheme economics for real schemes and, unlike the Cambridge study, does not relate this to installed capacity. However, there are two areas where comparison is possible but the results from the bottom-up analysis appear to be different to that of the econometric model, namely: • • Sensitivity to gas and electricity prices. Sensitivity to increases in the value for export electricity In the case of the bottom-up study, a 20% increase in electricity price made a significant number of the schemes economic and for export electricity, an addition of around £6-10 /MWh would be sufficient to make most of the example schemes economic. In the Cambridge Econometrics study, sensitivity to gas and electricity prices (including export) is less marked, with large differences in installed capacity requiring price changes of 40%. That study however attempts to model what will be installed, rather than what would be economic under a set of conditions. AEA Technology iii Contents 1 2 Introduction Methodology for the study 2.1 2.2 2.3 2.4 3 4 CONTACTS WITH SCHEMES SELECTED SITES ANALYSIS OF THE SAMPLE CALCULATION 1 3 3 4 5 6 8 10 13 14 19 Summary of Results Conclusions APPENDIX 1 ELEMENTS OF THE CHP MODEL APPENDIX 2 QUANTITATIVE RESULTS APPENDIX 3 SUMMARY OF VIEWS AND OBSERVATIONS RECEIVED AEA Technology iv 1 Introduction Combined Heat and Power (CHP) schemes can increase the overall efficiency of fuel use to 70-90%, by utilising the heat generated by the electricity generation process. As part of its strategy for reducing greenhouse gas emissions, the Government is committed to encouraging the growth of Good Quality CHP and has set a target of 10GWe by 2010. For a period during the 1990s, there was strong growth in CHP capacity, reaching close to 5GWe in 2000. Recently the economic climate has become increasingly difficult for CHP, for both new investment and existing installations, and the growth has slowed (Figure 1). Capacity at the end of 2002 was still around 5GWe although Future Energy Solutions is aware of a further 1 GWe of capacity that is expected to come on line by the end of 2004. The main reasons for the poor economic climate for CHP are: • Narrow spark spread. CHP is predominantly gas fired. Recent trends in electricity and gas prices have eroded the margin between gas and electricity tariffs (spark spread) (Figure 2). In 1998 and 1999, the spark spread was around £3 per MWh, reducing to £2 per MWh in 2002, representing a drop of around a third. There is evidence that for CHP schemes, the electricity price is lower than the average and the spark spread smaller still. The effects of spark-spread changes are not instant, as CHP schemes take time to develop and implement. The favourable spark spread in the years to 1999 produced a steady increase in capacity, with a peak in 2000. Since then, the spark spread has narrowed and the rate of development decreased. Over the last few months, electricity prices have risen again and there are some indications that the spark spread is increasing, creating more favourable market conditions for CHP development. Low electricity prices. Electricity prices as a whole have reduced steadily over the last 12 years by approximately 30% between 1990 and 20022 due to deregulation of the electricity industry. This has made it cheaper for sites to import electricity rather than investing in new CHP, or operating existing CHP. Uncertain export revenues. Export revenues have always been an important factor in the economic case for CHP. The introduction of the New Electricity Trading Arrangements (NETA) has been perceived by some as detrimental to CHP. Due to the nature of some CHP it can be difficult to predict export volumes and therefore the operators are more open to Balancing and Settlement system financial risks than more predictable plant. This negative perception of NETA has exacerbated the move away from CHP due to the uncertainty in the gas and electricity market prices. High instability in both gas and electricity prices. This makes forecasting future savings from CHP plant too uncertain for CHP developers to support investment decisions and it is difficult to obtain finance for projects. Such instability would also affect decisions for alternative generation • • • 2 DTI Quarterly Energy Prices, December 2002 AEA Technology 1 Figure 1 Change in installed Good Quality CHP, by total number of schemes and net capacity added per year 5,000 No. of sites / Installed capacity (MWe) 4,500 4,000 3,500 3,000 2,500 2,000 1,500 1,000 500 0 -500 1996 1997 1998 1999 2000 2001 2002 Number of sites Electrical capacity Net capacity added during year Figure 2 Average gas and electricity prices for the manufacturing sector3 4 Energy price, p/kWh 3.5 3 2.5 2 1.5 1 0.5 0 1998 1999 2000 Year 2001 2002 Average gas price, p/kWh Average electricity price, p/kWh The Government has introduced a number of measures to encourage CHP and in 2002 published a consultation on a draft CHP strategy. As part of the strategy development, 3 DTI Quarterly Energy Prices, December 2002 AEA Technology 2 Cambridge Econometrics undertook a study to project CHP capacity by 2010 under a variety of policy scenarios. An econometric model was developed using data on installed capacity to parameterise cost-benefit decisions for CHP schemes. This model was revised during 2003, using data for installed capacity to 2002 and some updated assumptions regarding the details of CHP scheme costs and timing were included. The model now projects that the Government target will not be met by 2010. The Cambridge Econometrics model projects for the market as a whole and is based on a topdown analysis using representative values for CHP schemes. Defra commissioned Future Energy Solutions to undertake a bottom-up analysis of CHP scheme economics using data from real schemes. This study complements the Cambridge Econometrics modelling by examining the effects of policies on individual schemes and testing some of the conclusions from the top-down model. The key objectives of this study are to provide: • • • Analysis of the economics of individual CHP schemes Analysis of the discrete impact of existing policies and measures on the economics of the selected CHP schemes; Analysis of the impact of potential future policies and measures on the economics of the CHP schemes. In this report, the methodology for the resultant study is outlined and the results discussed. Whilst selecting the schemes for analysis, effort was made to select representative examples with opportunities for CHP, as discussed in the next section. 2 2.1 Methodology for the study CONTACTS WITH SCHEMES The selection of potential sites was made on the following basis: • • • • • • A focus on Good Quality CHP. A focus on larger schemes, as these will contribute most to reaching the Government target. Coverage of a number of industrial and commercial sectors. Inclusion of a number of sites where the economics are marginal. A reassessment of sites that have considered CHP and have conducted detailed feasibility studies Mixes of sites, including some that were constructed and some that were withdrawn at the planning/design stage. AEA Technology 3 The selection procedure resulted in a list of potential contacts, who were approached to: • • Obtain qualitative information on the state of the market and on any factors of particular importance to these schemes. Obtain quantitative information, particularly economic data, for these schemes. In general, qualitative information was forthcoming. Obtaining quantitative information was more difficult, partly because of concerns regarding commercial sensitivity of the data and partly because of the limited resources of the Companies. Financial information was provided directly for 11 schemes, with information for an additional 3 being obtained from past feasibility studies. 2.2 SELECTED SITES Table 1 below summarises the technical characteristics of the selected sites and the economics at the time they were under consideration or development. The IRRs given in this report are pre-tax, real figures (2003 prices). A number of different criteria may be used to judge the economic viability of CHP schemes. As an alternative to IRR, the percentage saving on the energy bill that could be achieved by the larger schemes is presented4. The cost saving on the energy bill is for the project as a whole and does not include any consideration of who gains from the savings. Equally, the IRR is the return for the project as a whole and therefore would include any cost savings that would be realised by the heat customer. For most schemes, the energy prices were more favourable at that time. Table 1 – Scheme economic summary at the time they were under consideration Scheme Size category Part of Climate Change Agreement (CCA) No No Yes Yes No Yes Yes Yes Yes Yes Exports, % of generation IRR over 15 years for base case fuel tariffs 13% 1% 16% 23% 20% N/A5 4% 3% N/A4 15% % saving on energy bill 1 2 3 4 5 6 7 8 9 10 >50MWe >5MWe <50MWe >50MWe >5MWe <50MWe >50MWe >100MWe >5MWe <50MWe >5MWe <50MWe >50MWe >5MWe <50MWe 77 % 15 % 62 % 0% 92 % 85 % 40 % 100 % 73 % 25 % 35% 0 17% 6% 27% 0 0 17% 0 3% This compares the annual cost of the CHP with the cost of providing steam from boilers and importing electricity. A 10% discount rate over 15 years is assumed. 5 Historic prices not available 4 AEA Technology 4 Scheme Size category 11 12 13 14 <500 kWe <500 kWe <500 kWe <500 kWe Part of Climate Change Agreement (CCA) No No No No Exports, % of generation IRR over 15 years for base case fuel tariffs 38% 69% 23% 17% % saving on energy bill 0% 0% 0% 0% >10% >10% >10% >10% 2.3 ANALYSIS OF THE SAMPLE The sample comprises 14 schemes with a technical potential of around 400 MWe. Most of this capacity is from schemes above 10 MWe and under consideration in the period 19992001. In that same period the total CHP capacity that received consent6 was 3200 MWe7. Around half of that capacity has been commissioned or is still under development. The sample thus represents around 12% of the total consented capacity for that period. The study by Cambridge Econometrics projected future CHP capacity under different economic conditions. It is useful to compare the sector breakdown of the sample under favourable conditions with that of the projected potential of the sectors. The following table gives a breakdown by sector of the sample compared to the breakdown by sector of the additional technical capacity (2002 – 2010) from Cambridge Econometrics modelling. Table 2 Analysis of the sample Projected additional capacity under % sample represents of favourable economic conditions projected additional from the CE study MWe capacity 1187 2% 3255 9% 3025 0% 738 9% 85 0% 8290 5% Chemicals Other + power +minerals* Own use (refineries) Commerce and household Iron and steel Total The sample for two sectors, ‘other’ and ‘commerce’ each represents nearly 10% of the projected technical capacity for those sectors and in chemicals 2%. The most significant category where there is no representation in the sample is ‘own use (refineries)’. It was not possible within the scope of this study to obtain data for schemes that would be representative of future developments in refineries. Conoco Philips at their Humber refinery are currently developing a large CHP scheme. This scheme will represent around 8% of the 2010 target for capacity. However, it was felt that, because of its size, the scheme would not be a typical example even for refineries. The sample has also been analysed for the size breakdown taken from the Cambridge Econometrics projections under favourable economic conditions (Table 3). 6 7 Under Section 36 of the Electricity Act 1989 and Section 14 of the Energy Act 1976. Digest of UK Energy Statistics 2001. AEA Technology 5 Table 3 Analysis of the sample by size category Projected additional capacity % sample represents of under favourable economic projected additional capacity conditions from the CE study MWe 250 <1% 919 0% 3316 2% 3804 9% 8290 5% 0-500kWe 500kWe - 5MWe 5MWe – 50MWe >50MWe Total The sample for the largest schemes represents 9% of the additional capacity in that category from the Cambridge Econometrics modelling. For the next largest schemes, the sample is 2% of the potential. There are four smaller schemes included in the study, but these represent only a small proportion of the additional capacity. 2.4 CALCULATION The aim of the modelling carried out for this report was to look at the economics of individual schemes. A simplified representation of the scheme economics was used, based on annual data. Although individual scheme economics can be influenced by details such as the heat and electricity profiles, initial yes/no decisions are likely to be made on the annual data. The model compares the costs of a CHP scheme with existing boilers and electricity imports, or in some cases existing CHP. Thus the costs for CHP are compared only with the costs of providing heat from an existing boiler, not the additional capital costs of installing a new boiler. A list of the model parameters is provided in Appendix 1. The model calculates the financial returns for a specified project i.e. the internal rate of return (IRR), net present value (npv), percentage savings on the energy bill and simple payback. Only the IRR results are discussed in detail here since this is the most robust measure of financial return used by the industry. In the current market conditions, CHP developers would be willing to invest in projects giving an IRR of 15% or greater (over a 15 year period). A number of scenarios were tested: 1) Scheme specific base case – this represents the base case assuming current fiscal measures are in place with scheme specific prices. The current fiscal measures are climate change levy (CCL) exemption for Good Quality CHP inputs and outputs, reduction of 80% on the CCL for participants in Climate Change Agreements (CCA), Enhanced Capital Allowances (ECA), the effect of the new electricity trading arrangements (NETA) was also incorporated. Some of the sites originally considered CHP prior to the introduction of these fiscal benefits, and the economics were updated to include their effect. 2) Varying fiscal measures. Effect of current measures on scheme economics relative to the base case. For each scheme, current measures such as Enhanced Capital Allowances, Climate Change Agreements, Levy exemption on electricity exports, were individually modified to assess the effects upon the economics as follows: AEA Technology 6 a) Effect of CCL exemption. The scheme economics were calculated including ECAs, but with no CCL exemption on fuel or electricity b) Effect of extension of CCL exemption to electricity exported to a licensed supplier (indirect supply). ECAs and CCL exemption on fuel and on-site electricity were included in the calculation but no CCL exemption on exported electricity c) Effect of ECAs. CCL exemption included for fuel and all electricity but no ECAs for the capital expenditure. d) Effect of NETA removed. CCL exemption for fuel and electricity and ECAs on the capital expenditure were included and a higher export price was assumed. The assumed effect of NETA on export prices is £2/MWh, so this value was added to the export price. 3) Scheme economics with 2003 prices (Table 1) provided by DTI for the Cambridge Econometrics modelling (Price Scenario A). This provides a comparison of the scheme economics using the same assumptions for each scheme on implemented policies and fuel prices. The prices provided by DTI are not applicable to the smallscale CHP schemes 11-14. For these schemes, an average of the prices collected by the FES team was used in this Scenario. 4) Scheme economics in 2003 but with an alternative pricing structure (Price Scenario B). Price Scenario B represents a change in the price structure reflecting the projected structure for 2010 expressed in real 2003 prices. This scenario does not reflect the position in 2010, but represents the situation if this price structure were to apply now. For the small-scale schemes, the same relative change in the prices compared to Scenario A was used. Table 4 Fuel prices provided by DTI in real 2003 prices Gas price Electricity import price (excl CCL) Electricity export price Price Scenario A £7.3/MWh £24.5 /MWh £18.8 /MWh Price Scenario B £7.5 /MWh £26.7/MWh £21 /MWh 5) Different policy scenarios A number of policy scenarios have also been used to illustrate the effect of a range of possible policies. Practical difficulties with implementing any of these policies have not been considered here. a) Sensitivity around gas and electricity prices. ±10%, ±20% separately on gas and electricity. Additional sensitivity of +30% and +40% on electricity prices and –30% and –40% on gas prices was calculated. The modelling neglects any link between gas and electricity prices. b) Policy scenario – exemption of CHP from the renewable obligation base. The CHP industry is seeking to exempt Good Quality CHP exports from the base for a supplier under the Renewables Obligation. The value of this to a supplier is determined by the buy-out price multiplied by the annual percentage target. The annual percentage target increases to 10.4% by 2010, in 2003 prices this gives a value of £3.1/MWh. Assuming that 90% of this value would be passed through to the CHP operator, this policy measure is represented by adding £2.8/MWh to the export price for electricity AEA Technology 7 c) Policy scenario – a CHP obligation. i. Fixed value for CHP obligation. A CHP obligation would operate in a similar way to the Renewables Obligation and is modelled by adding a value to the export price for electricity. A range of values was given in the Cambridge Econometrics model. The lower end of the range is covered by Scenario 5b, the higher end is £20/MWh to be added to the export price. ii. A CHP obligation to reach 15% IRR. In this scenario the value that would need to be added to the export price for the scheme to achieve 15% IRR is calculated. It is referred to as an obligation for simplicity, but could in fact be achieved through a combination of policies. d) Policy scenario – with the EU emissions trading scheme (EU-ETS). It is assumed that CHP schemes are allocated sufficient permits to cover their emissions and that the only effect of the EU-ETS is through increased electricity prices. This effect is calculated by assuming that the whole cost of carbon is passed through in the price of electricity. The extra cost is calculated assuming a carbon price of £26/tC (based on estimated prices of 10 euro/tCO2) and an average emission factor for electricity from fossil fuel generation of 142 g/kWh, based on projections assuming an increase in the proportion of gas generation. 3 Summary of Results The detailed results from the calculations and an analysis of the views and observations are presented in Appendix 2. A summary is presented here. • • • • The IRR and percentage savings for all schemes are reduced in price scenarios A and B compared to the base case The financial return improves between scenario A and B as the spark spread increases, but only to a limited extent The largest effect from existing policies is from the exemption from the CCL, if this is removed the economics for most schemes would be significantly worse. For most schemes, the IRR is more sensitive to electricity prices than gas prices; generally a 10% change in electricity produces the same effect as a 20% change in gas price. Price changes of 20% in the electricity price gives positive savings on the energy bill and an IRR of greater than 15% for four additional schemes. With 40% increase, only one Scheme returns an IRR of less than 15% For £20 added to the export price as a CHP obligation, 10 schemes have a return of greater than 15%. A different 10 schemes return more than 15% with the carbon price from the EU-ETS passed through in electricity prices. An obligation of around £6 per MWh would be sufficient to make around half the capacity economic. If the price of electricity increases because of the EU-ETS, the obligation price needed to make schemes economic is decreased. Only one additional scheme achieves 15% IRR with the exemption from the RO base. • • • • AEA Technology 8 Table 5 below summarises the position of each scheme Table 5 - Scheme Summary Schem e Summary 1 2 3 4 5 6 7 Scheme 1 exports a significant proportion of the electricity generated. At the time the scheme was being designed (base case), it was financially viable but other problems delayed the decision to implement. Under the two price scenarios the IRR is less than 15%. The large proportion of exports means that the economics are sensitive to the export price and policies such as the extension of the CCL exemption to indirect supply. This scheme is not part of a climate change agreement. Scheme 2 exports a small proportion of the electricity generated. At the time of design it would appear that it was not particularly financially attractive. It was implemented for technical reasons, which cannot be properly reflected in the financial benefits included in our calculation. The scheme economics are made worse using the two price scenarios. With only a small proportion of exports, the scheme economics are not sensitive to export price and less sensitive than most of the other schemes to the EU-ETS. This scheme is not part of a climate change agreement. Scheme 3 exports a significant proportion of electricity. At the time of design, we calculate that the scheme returned an IRR of 16% and it went ahead. It is sensitive to the export price and to Government policies that have influence on the export price. Scheme 4 is sized to meet site demands with no exports. The cost effectiveness of this scheme is good (14% IRR), even with the current pricing structure. However, it is in an industry where there have been major uncertainties in ownership and the scheme has not been developed. Because there are no exports, the economics are not sensitive to the policies to increase export price. Scheme 5 exports most of the electricity. At the time of design it was economic and has been implemented. The fall in export price has had a severe effect on the economics of this scheme, and with the two price scenarios the return is significantly less than 15%. There is a modest benefit from the EU-ETS. Scheme 6 exports a large proportion of electricity, but uses all the heat on site. This scheme has not gone ahead, although the host site is keen to keep the project under review. The economics of the scheme are very sensitive to the export price and consequently would benefit significantly from EU-ETS. Scheme 7 exports a small proportion of the electricity. The return is less than 15% for all cases, but improves between price scenario A and B. The behaviour between these scenarios is different from the other schemes because the comparison is with existing oil-fired boilers and the price structures are different. In reality since the feasibility study for this scheme, the boilers have been replaced recently with new gas boilers and it is unlikely that CHP would be considered again at this site in the near future. The site is part of a CCA. AEA Technology 9 8 9 10 11-14 Scheme 8 exports all the electricity generated (there is an existing CHP that supplies site electricity demands). The scheme is not economic under any of these scenarios and did not go ahead. It is sensitive to policies aimed at increasing the price of exports but is not part of a CCA. Scheme 9 exports a large proportion of electricity and is on a site that is part of a CCA. It is uneconomic and did not go ahead. Scheme 10 exports 25% of the electricity generated. It is uneconomic in the base case because there was a small differential between the import and export price for electricity for that site. With the two price scenarios, the situation improves but the scheme has not gone ahead. Due to the relatively low level of exports, it is less sensitive than some of the other schemes to the export price. Schemes 11 to 14 are small schemes with no electricity exports. Even under current market conditions the economics are very favourable, mainly due to the high cost of imported electricity. These type of schemes will not be affected by the measures aimed at increasing the value of exported electricity. 4 Conclusions The schemes that are most affected by market conditions are those that export a significant proportion of their electricity output. Most developers of large schemes would be looking to develop this type of scheme to form part of their generation portfolio. The changes in the energy markets have hit the economics for this type of scheme very significantly and resulted in a loss of confidence in the market. A key concern for many of the developers/operators was the lack of stability in energy prices. Government policies to add value to the export prices would favourably influence the economics for these schemes and send positive signals to the market. Where there is significant export, the schemes tend to have relatively high electrical efficiency and higher energy and carbon savings. A policy to encourage such schemes would therefore be consistent with other aims of Government policy. In the current market where medium to large-scale CHP is at best marginally economic, the high level of uncertainty due to energy price fluctuations is an additional burden for CHP. Some of the policy options analysed, such as the EU-ETS, are also inherently uncertain and their value could be discounted in investment decisions. However, even in current market conditions, some small-scale CHP schemes are economic and can provide attractive returns on investment. At this size, the import price for electricity is important in determining the economics of schemes. The Cambridge Econometrics model projects CHP capacity on the basis of econometric analysis and financial returns on average CHP costs. The analysis presented here looks at individual scheme economics for real schemes but does not try to relate this to the capacity that might actually be installed. However, there are two areas where the results from the bottom-up analysis appear to be significantly different to the econometric model and where further consideration may be beneficial. • Sensitivity to gas and electricity prices. A 20% increase in electricity price in the bottom-up analysis made a significant number of the schemes economic and at a 40% AEA Technology 10 increase nearly all the Schemes become economically attractive. In the Cambridge Econometrics modelling a 20% increase in electricity price produced a 7% increase in capacity and a 40% increase in electricity price would produce a 30% increase in capacity. • Sensitivity to increases in the value for export electricity. For the example schemes, an addition of around £6 per MWh would be sufficient to make approximately half of the modelled capacity economic, and with the majority economic by £10 per MWh. In the Cambridge Econometrics model, an obligation price of £20 per MWh by 2010 is needed to reach the Government target of 10 GWe. AEA Technology 11 Appendices CONTENTS Appendix 1 Appendix 2 Appendix 3 Elements of the CHP model Results and summary of responses Summary of views and observations received AEA Technology 12 APPENDIX 1 ELEMENTS OF THE CHP MODEL Site demands for heat and electricity – total annual figures Existing situation • Fuel use of boilers or CHP • Fuel price for boilers or CHP • Electricity used on site • Price for electricity used on site • CCL exemptions where site is part of a CCA CHP scheme • Capital costs • Enhanced capital allowances • Operation and maintenance costs over and above that for the boilers • Fuel use for CHP • Proportion of fuel eligible for exemption under CHPQA • Electricity generated by CHP and used on site • Electricity imports to top up demand • Electricity exports • Proportion of electricity eligible for exemption under CHPQA • Fuel price for CHP, if gas it is assumed that this is the same as for the boilers although in practice it could be affected by changes in the demand • Price for electricity imports • Price for electricity exports AEA Technology 13 APPENDIX 2 QUANTITATIVE RESULTS Figure 3 shows the IRR for the example CHP schemes studied for the base case and price scenarios A and B in Table 4. In most cases, the IRR is reduced by the use of scenario A. This is in part because of the decrease in spark spread, but also reflects that some schemes are able to negotiate favourable site-specific prices. The IRR for all schemes improve using the price scenario B compared to price scenario A. For example, in the base case, schemes 1, 3, 4 and 5 and all the small-scale schemes would return more than 15% IRR. All four of the larger schemes reduce to below 15% in price scenario A. In price scenario B, only one of these four returns to more than 15% and this is also the only scheme that provides positive cost savings on the energy bills. The financial return improves between scenario A and B as the spark spread increases. Figure 3 Internal Rate of Return (IRR) for example CHP schemes 80.00% 70.00% 60.00% 50.00% 40.00% 30.00% 20.00% Scheme 1 Scheme 2 Scheme 3 Scheme 4 Scheme 5 Scheme 6 Scheme 7 Scheme 8 Scheme 9 Scheme 10 Scheme 11 Scheme 12 Scheme 13 Scheme 14 10.00% 0.00% Base case Scenario A Scenario B For each of the sites, the effects of removing individual fiscal benefits, such as Enhanced Capital Allowances or CCL exemption, was modelled. The impact on IRR of these measures is shown in Figures 5 and 6. The only scenario to have a positive effect on the IRR is the removal of the NETA effect. The largest relative change in IRR is for the removal of the CCL exemption. If CHP schemes were not able to obtain exemption from the CCL, the IRR for some schemes could be as much as halved. The reason for this large effect is that the CCL exemption improves the price differential between CHP and conventional alternatives for both fuel and electricity. The benefit of the exemption however is reduced for schemes within CCAs as they are only liable in any case for 20% of the levy. The largest changes in IRR for the extension of levy exemption to indirect supply are for schemes 6 and 8, as they AEA Technology 14 export a significant proportion of their output. Measures such as NETA and the extension of CCL exemption to indirect supplies do not change the economics of the small-scale schemes 11-14 as they are sized for on-site use and do not export electricity. ECAs have only a small effect on the overall economics and NETA, as would be expected, affects most the schemes with the largest proportion of exports. Figure 4 IRR for example CHP schemes for current policies 80% 70% 60% 50% 40% IRR Scheme 1 Scheme 2 Scheme 3 Scheme 4 Scheme 5 Scheme 6 Scheme 7 Scheme 8 Scheme 9 Scheme 10 Scheme 11 Scheme 12 Scheme 13 Scheme 14 30% 20% 10% 0% -10% Base case Base case prices No ccl exemption no ccl exemption for direct supply No ECA No NETA Sensitivity to the electricity and gas prices is illustrated in Figure 5 (a) and (b) and Figure 6 (a) and (b). For most schemes, the IRR is more sensitive to electricity than gas prices; generally a 10% change in electricity produces the same effect as a 20% change in gas price. If gas prices were to fall by 40%, seven of the 10 larger schemes (370 MWe) would have an IRR greater than 15%. If electricity prices increase by 20%, the IRR for six larger-scale schemes increases above 15% and positive savings of between 1% and 20% on the energy bill are achieved for four schemes. With a 40% increase only Scheme 2 returns an IRR of less than 15%. The six schemes represent 250 MWe capacity and the nine schemes 385 MWe. The small-scale schemes are included separately for clarity. AEA Technology 15 Figure 5 (a) Sensitivity to gas price variation for larger scale schemes (Price scenario B) 25% 20% Scheme 1 Scheme 2 Scheme 3 Scheme 4 Scheme 5 Scheme 6 Scheme 7 Scheme 8 Scheme 9 Scheme 10 15% IRR 10% 5% 0% -50 -40 -30 -20 -10 0 10 20 30 Gas price variation (b) Sensitivity to gas price variation for small-scale schemes (Price scenario B) 65% 55% 45% 35% IRR 25% Scheme 11 Scheme 12 Scheme 13 Scheme 14 15% 5% -5% -25 -20 -15 -10 -5 0 5 10 15 20 25 Gas price variation AEA Technology 16 Figure 6 (a) Sensitivity to electricity price variation for larger-scale schemes (Price scenario B) 35% 30% 25% 20% 15% IRR 10% 5% 0% -5% -10% -30 -20 -10 0 10 20 30 40 50 Electricity price variation (%) Scheme 1 Scheme 2 Scheme 3 Scheme 4 Scheme 5 Scheme 6 Scheme 7 Scheme 8 Scheme 9 Scheme 10 (b) Sensitivity to electricity price variation for small-scale schemes (Price scenario B) 75% 65% 55% 45% 35% 25% 15% 5% -5% -25 -20 -15 -10 -5 0 5 10 15 20 25 Electricity price variation (%) Scheme 11 Scheme 12 Scheme 13 Scheme 14 IRR AEA Technology 17 The IRR for the different policy options is shown in Figure 7 with Scenario B as the base. Only one additional scheme achieves 15% IRR with £2.8 added to the export price i.e. with exemption from the renewable obligation base. For £20 added to the export price as a CHP obligation, 10 schemes have returns of greater than 15%. For the EU-ETS scenario if a carbon price of £7/tCO2 is passed through to the wholesale electricity price a different ten schemes have returns of greater than 15%. These ten schemes represent 300 MWe potential capacity. Figure 7 IRR for different policy options 60% 50% Scheme 1 Scheme 2 Scheme 3 Scheme 4 Scheme 5 Scheme 6 Scheme 7 Scheme 8 Scheme 9 Scheme 10 Scheme 11 Scheme 12 Scheme 13 Scheme 14 40% IRR 30% 20% 10% 0% Scenario B base Scenario B prices 2.8 exempt RO Scenario B prices 20.3 chp obligation Scenario B prices ETS (£7/tCO2) The renewable obligation exemption and CHP obligation applies to export volumes and the magnitude of the effect is dependent upon the level of exports from each scheme. Schemes 1, 5, 6 and 8 export a significant proportion of their output and are therefore affected most by these measures. Scheme 4 does not export electricity and the IRR is therefore unaffected by any level of obligation. The EU ETS affects both electricity imports and exports and therefore has an impact on all schemes, with the greatest impact on Scheme 6 as it exports a significant amount of electricity. The models were run to ascertain an indicative level of obligation that would be required to give a return of 15%. The results are shown in Table 6 below. Schemes 2 and 7 would require a very large obligation due to the fact that their export volumes (15% and 40% respectively) are significantly lower than the other schemes, which export more than 75% of their output. When the effect of the EU-ETS is taken into account a much lower level of obligation price would be needed to give 15% IRR for most schemes. An obligation price of £4 /MWh would be sufficient to make 380 MWe out of the 400 MWe economic. The small-scale schemes and Scheme 4 are designed to operate to provide generation for on-site use only and an obligation will have no impact on their viability. AEA Technology 18 Table 6 ‘Obligation price’ (£/MWh) needed to give 15% IRR (Price Scenario B) Scheme Scheme Scheme Scheme Scheme Scheme Scheme Scheme Scheme Scheme 1 2 3 4 5 6 7 8 9 10 Obligation price to reach 8 15% Obligation price to reach 1 15% with EUETS 96 6 0 4 7 27 8 2 5 72 0 0 0 0 17 4 0 0 As indicated in Table 1 of section 2.2, the majority of schemes are part of a Climate Change Agreement (CCA), which allows them an 80% reduction on Climate Change Levy on all natural gas. For these sites, the extra benefit that can be claimed by having a good quality CHP scheme is therefore only 20% of the value of the CCL for fuel. The fiscal benefit of installing CHP is therefore eroded significantly for a site that is part of a CCA. Schemes 1, 2 and 5 are not part of a CCA; hence the IRR is unchanged between the two cases shown in Figure 11. For the other schemes (Schemes 3, 4 and 6 to 10) it can be seen that the case for CHP would be stronger if they did not get the reduction on the CCL, as the IRR of the ‘2003 No CCA’ scenario in Figure 11 increases for all of such schemes. This reflects the fact that CCA agreements effectively reduce the cost of imported electricity displaced by CHP. Figure 11 Effect of removal of CCA 25.00% 20.00% 15.00% 10.00% Series1 Series2 Series3 Series4 Series5 Series6 Series7 Series8 Series9 Series10 IRR 5.00% 0.00% Scenario A prices Scenario A prices - no CCA AEA Technology 19 APPENDIX 3 SUMMARY OF VIEWS AND OBSERVATIONS RECEIVED In carrying out this study contact was made with many significant players within the CHP industry. While not all of them were able to provide the project specific information that was requested, virtually all of those contacted were keen to express their views of the CHP market based on individual experiences over recent years. The following is a summary of the comments that were received: 1) The unfavourable combination of gas and electricity prices (the ‘spark spread’ or ‘spark gap’). Currently the benefits of generating for export are regarded as marginal at best and, in many cases, simply uneconomic. Reference to this issue was almost universal and it appears to have been the primary factor that led to the re-evaluation and subsequent suspension of many schemes that were under development. Many respondents felt that NETA and its consequences had been particularly unhelpful to CHP and that the economics of many schemes had been undermined very quickly following its introduction. The narrow spark spread has also had an effect on the way many CHP schemes operate. A number of operators stated that it is currently more economic to run their plants at part load to meet the heat demand only with any electricity shortfall made up by importing. Some commented that there has been a modest improvement in the situation recently but not enough to make a significant difference as yet. Since NETA the spark spread has typically been 3:1 or less (e.g. electricity at £20/MWh and gas at 19.6p/therm, equivalent to £6.66/MWh at 50% efficiency, equates to a spark spread of 3:1). Few respondents ventured to suggest what an acceptable combination of gas and electricity prices ought to be. However, one estimated that a sustained net increase of £5/MWh in the electricity price would be necessary while another suggested that for schemes at the smaller end of the scale, the spark spread ought to be around 4:1. Without a significant decrease in gas prices, 4:1 would imply net electricity prices increased by the order of £6-7/MWh. 2) Industrial customers unable to guarantee heat & power demand beyond the shortterm due to long-term uncertainties in productive output. This is a problem that mainly affects schemes that are developed by a third party on a host site. Such developers are looking for a long-term commitment (10-15 years) whereas many industrial customers are unable to guarantee their level of production beyond the next year or two. 3) Payback periods are now much longer than they were making many schemes unattractive to investors. A few years ago typical project paybacks were as little as five years. Payback periods at the moment are typically much greater than 5 years. If conservative assumptions are used, many projects currently slip into negative payback. 4) CCL benefits do not make a significant difference to project viability. There were mixed messages regarding the value of LECs. Some felt they were of marginal importance to their overall schemes while others felt they were relatively important but were concerned that future changes in government and policies might erode the benefits. It was suggested that if all output from CHP qualified for LECs, it would AEA Technology 20 potentially make a significant difference to the economics. Currently, some schemes get LECs for only a small proportion of their output. This point was taken further by the suggestion that CHP operators would derive much greater benefits if a mechanism was developed to link the LEC benefits to gas consumption rather than exported electrical output. 5) Long-term instability and lack of confidence. The recent experience of many developers means that, even if conditions were to become more favourable in the near future, confidence will remain low and few will invest until they are sure that the improvement will be sustained. Hence, to be effective, measures should be taken to stabilise the market for the next 5-10 years or more. 6) Increasing bureaucracy. Those operating just one or two relatively small plants complained about the increasing burden of more monitoring, auditing, reporting etc. that is required to comply with both existing and forthcoming rules and regulations. It is perceived that larger operators can absorb such costs by spreading them around whereas individual operators cannot. 7) More attractive investment options. Where there is a limited ‘pot’ for investment, other options such as renewables and energy efficiency measures are often regarded as more attractive than CHP. 8) Plant renewals. In the current climate many industrial developers are choosing to renew or refurbish outdated plant with new boilers rather than installing CHP. In such cases, it will be many years until a further review is carried out and the opportunity to invest in CHP arises again. 9) Negotiating positions. Sites with very flat, predictable demand (such as hospitals) are able to negotiate very low electricity tariffs. Although CHP would often be suited to such sites, many customers are not persuaded to relinquish their strong negotiating position by agreeing to the long-term agreements that are required to recover the capital investment in CHP. 10) Loss of expertise and capability. Many of the larger developers have now disbanded their CHP project teams. Even if such players did decide to re-enter the market, it will take some time to re-establish their capability in the field and probably several more years before the first new schemes are developed and commissioned. 11) Lack of incentives. It was suggested that targets for energy efficiency savings might not have been stringent enough as many customers have met their targets with relatively modest improvements and without resorting to major investments such as CHP. 12) Planning issues. A few developers felt that planning issues continue to frustrate and delay many projects. However, this is probably not a feature that is unique to CHP. AEA Technology 21