Combined heat and power in the Swedish district heating sector—impact of green certificates and CO2 trading on new investments

ARTICLE IN PRESS

Energy Policy 34 (2006) 3942–3952 www.elsevier.com/locate/enpol

Combined heat and power in the Swedish district heating sector— impact of green certificates and CO2 trading on new investments David Knutsson, Sven Werner, Erik O. Ahlgren Energy Systems Technology, Department of Energy and Environment, Chalmers University of Technology, SE-412 96 Gothenburg, Sweden Received 24 March 2005; received in revised form 21 September 2005 Available online 2 November 2005

Abstract Combined heat and power (CHP) has been identified by the EU administration as an important means of reducing CO2-emissions and increasing the energy efficiency. In Sweden, only about one third of the demand for district heat (DH) is supplied from CHP. This share could be significantly larger if the profitability of CHP generation increased. The objective of this study was to analyse the extent to which the profitability for investments in new CHP plants in the Swedish DH sector have changed thanks to the recently implemented trading schemes for green certificates (TGCs) and CO2 emissions (TEPs). The analysis was carried out using a simulation model of the Swedish DH sector in which the profitability of CHP investments for all DH systems, with and without the two trading schemes applied, is compared. In addition, a comparison was made of the changes in CHP generation, CO2 emissions, and operation costs if investments are made in the CHP plant shown to be most profitable in each system according to the model. The study shows that the profitability of investments in CHP plants increased significantly with the introductions of TGC and TEP schemes. If all DH utilities also undertook their most profitable CHP investments, the results indicate a major increase in power generation which, in turn, would reduce the CO2 emissions from the European power sector by up to 13 Mton/year, assuming that coal condensing power is displaced. r 2005 Elsevier Ltd. All rights reserved. Keywords: Tradable green certificates; Tradable emission permits; Combined heat and power (CHP)

Increased use of combined heat and power (CHP)1 and renewable energy sources (RES) is generally recognised by the EU administration as effective means of increasing the overall energy efficiency of the energy systems, reducing the CO2 emissions and reducing the dependency on imported fuels (European Parliament, 2001, 2004). Among the EU member states, Sweden is perhaps the country best suited for additional CHP generation as outlined below. The annual Swedish district heating (DH) deliveries today amount to about 50 TWh, corresponding

to about 47% of the final energy consumption in residential and other premises (Statistics Sweden, 2004a). Only about one third of the DH supplies, however, originate from CHP plants (Swedish District Heating Association (SDHA), 2003). One explanation is the historically low Swedish power prices, which have made investments in CHP plants unprofitable.2 Increased profitability of CHP generation would thus increase the possibilities for additional power generation in the DH sector. Large possibilities should also be present for increasing the use of biofuel in Sweden, see e.g. Johansson and Lundqvist (1999) and Swedish Energy Agency (SEA) (2002).3

Corresponding author. Tel.: +46(0)317725246; fax: +46(0)317723592. E-mail address: [email protected] (D. Knutsson). 1 In a CHP plant, useful heat, e.g. district heat, and power are generated simultaneously with an overall energy conversion efficiency of about 90%.

2 Dominant hydropower resources in combination with an extensive nuclear power programme in the 1970s and 80s resulted in good access to low-cost power. 3 In spite of good access to biofuels in Sweden, the rapid expansion of the use of biofuel in the Swedish DH sector since the early 1990s has partly

1. Introduction

0301-4215/$ - see front matter r 2005 Elsevier Ltd. All rights reserved. doi:10.1016/j.enpol.2005.09.015

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Two recently introduced energy policy instruments may have substantially increased the profitability of investments in CHP plants in Sweden: the legally binding scheme for tradable green certificates (TGCs) introduced in Sweden on May 1, 2003 (Swedish Parliament, 2003), and the tradable CO2 emission permit (TEP) scheme introduced in the EU on January 1, 2005 (European Parliament, 2003b).4 The purpose of the TGC scheme is to increase the financial incentives for investment and operation of power generation technologies based on RES.5 The TEP scheme is one of the three ‘‘flexible mechanisms’’ in the Kyoto protocol, intended to enable cost effective greenhouse gas reductions (UNFCCC, 2004).6 While the effects of the TGC scheme on the profitability of CHP investments is direct (through granting of TGCs in relation to the production), the increased profitability owing to the TEP scheme is related to the increase in power prices the TEP scheme is likely to give rise to, as explained in Section 2.3. In the calculations of the Swedish government commission that investigated the design and consequences of the TGC scheme prior to its implementation (SOU, 2001) the results indicated a dominant position for biofuel CHP in the TGC scheme, particularly during the first years. The increase was shown to comprise a mix of both switching from coal to biofuels in existing CHP plants and installations in new biofuel CHP plants. A few later studies have analysed the implications for the energy system of the TGC and TEP schemes together. For instance, Unger and Ahlgren (2005) analysed the implications of the co-existence of electricity, TEP, and TGC markets in the Nordic countries. In this study common Nordic TGC and TEP schemes were assumed. In accordance with SOU (2001) above, also this study showed a major role for existing CHP plants in Sweden in the TGC scheme during the first years. Only a minor share of the additional TGC eligible power generation would come

(footnote continued) been accomplished using imports. National differences in energy policies between Sweden and the exporting countries have been suggested to be the main reason (Ericsson and Nilsson, 2004). 4 Another Swedish measure that has also increased the profitability of CHP generation, but in contrast to the TGC system, favours fossil fuelbased CHP is the change in the CHP taxation regime that took place on January 1, 2004. Prior to this date, heat generation based on fossil fuels in CHP plants was taxed at 50% of the energy tax and 100% of the CO2 tax (see Table 2). Corresponding rates after this date are 0% and 21% (Swedish Parliament, 1994). The taxation regime for HOBs is unchanged, 100% of the energy tax and 100% of the CO2 tax. Power generation is always tax exempt in Sweden. The effects of this change on the profitability of CHP investments are not investigated in this paper. 5 TGC eligible fuels are biogas, tall-oil pitch, peat, and wood fuels (SOU, 2001). These fuels are also referred to as renewable in the analysis. 6 The other two are; joint implementation (JI) and the clean development mechanism (CDM). The EU commitment in the Kyoto protocol is to reduce the greenhouse gas emissions by 8% by 2008-2012 as compared with the 1990 levels.

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from constructions of new biofuel-based CHP plants. Hindsberger et al. (2003), made a similar analysis, but with the focus one the whole Baltic Sea region. In this study a common TGC scheme for Denmark, Finland, Germany and Sweden was assumed. The TEP scheme was assumed to include Denmark, Finland, Norway and Sweden. The results from this study showed a power generation increase of 4.8 TWh/year from new bio and waste plants in Sweden in 2010 as a result of the introduction of the TGC scheme. The corresponding figure with the TGC and TEP schemes both applied was calculated to 5.3 TWh/year. One study that focused on implications for the future Swedish CHP generation of introducing TGC and TEP schemes found that the two schemes together would create financial incentives for investments in CHP plants correspondent to 3.8 TWh of annual power generation (Profu, 2003). All the studies referred to above were carried out at the aggregated system level. In Unger and Ahlgren (2005), and Hindsberger et al. (2003), the MARKAL model (Fishbone and Abilock, 1981), and the BALMOREL model (Ravn, 2001) were used, respectively. Typical for these models is that they describe the national DH sectors as one or a few type systems. The reason for this is that they are applied for analyses of the whole energy system and therefore lack possibility to describe each subsystem in detail. In the Profu (2003) study, in which the DH system simulation model MARTES (Johnsson and Rossing, 2003) was used, the analysis was carried out by analysing the largest DH systems in detail and, subsequently, up-scaling the results in order for the model to represent the national DH sector. Since the response of the DH utilities of the introduction of the TGC and TEP scheme are likely to vary considerably for all DH utilities, aggregated approaches such as the ones above can only give a rough indication of how the DH sector actually will develop. It was also shown in Knutsson et al. (2005) that the level of aggregation in analysis of the Swedish DH sector may be important for the quality of the results. The aim of the present study was to investigate how the profitability of investments in new CHP plants in the Swedish DH sector has changed since the introduction of the two trading schemes, and to do so with greater precision than has been done in the past. Another aim was to analyse the changes in CHP generation, CO2 emissions, and operation costs if the CHP plant shown to be most profitable in each system is actually invested in. The study is carried out by simulating the most profitable CHP investment for every Swedish DH system with and without the two trading schemes. The paper is organized as follows: Chapter 2 explains the method of the analysis including construction and application of model, assumptions and data and, the scenarios analysed. Chapter 3 presents the results of the analysis. Chapters 4 and 5 cover discussion and conclusions from the analysis.

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2. Theory and model

1400

The analysis was performed with a newly developed model, the HEATSPOT model.7 The model is static and considers the supply and demand sides of the existing Swedish DH sector. The construction and application of the model are explained briefly in Sections 2.1 and 2.2. Descriptions of the HEATSPOT model can also be found in Sahlin et al. (2004) and in Knutsson et al. (2006).

1200

1000

MW heat

Oil HOB

2.1. Model construction

Biomass HOB

C h ¼ bh þ bel þ g þ d
e =MW hheat  where

bel ¼

g¼ 7

600

400

In the HEATSPOT model, 172 local DH systems, corresponding to 99% of the Swedish DH generation, are described system by system. Each system is described with an annual load duration curve and a set of heat generating technologies. The description of the annual load duration curves for the DH systems is based on statistics on temperature frequencies over a 21-year period (Taesler, 1972). The set of heat generation technologies is calculated using the annual load duration curve together with data on annual fuel consumption (SDHA, 2000, 2001, 2002, 2003) and annual average order of dispatch (annual average heat generating cost (C h )) for the technologies8 using the relation below. The C h relation is valid both for heat-only boilers (HOBs) and for CHP plants. For CHP plants, all costs are allocated to heat generation, after which the revenues from power and TGC sales are deducted.9

bh ¼

800

C f ;h þ STaxE ;h  TaxE þ STaxCO2 ;h  TaxCO2 Ztot ðC f ;el þ S TaxE ;el  TaxE þ S TaxCO2 ;el  TaxCO2 Þ  a Ztot

C O&M v  ð1 þ aÞ Ztot

HEATSPOT is an acronym for Simulating POTential changes in district HEATing sector. 8 Information on annual fuel consumption (and estimated conversion efficiency) gives the annual DH production from each fuel (plant) (MWh).The order of dispatch together with the annual load duration curve gives information on the annual time of operation of the plant (h). The annual DH production divided by the annual operation time gives the production capacity of the plant (MW). The capacities are calculated for four different years in order to lower the risk of using data from a year that deviates considerably for some reason from an average year. The mean values of the capacities for the four years are then used as input to the model. 9 In the calculation of the capacities for the existing plants in the model, revenues from TGC sales (RTGC) are not considered since the TGC scheme had not been introduced at the time when the model was constructed. The same holds true for the cost of TEPs (C TEP ). These are, however, important variables in the calculations of C h for the different units in the analysis below.

Heat pump 200 Industrial waste heat 0 0

2000

4000 Hours

6000

8000

Fig. 1. Illustration of a district heating (DH) system as described in the HEATSPOT model.

d¼

C TEP ðEF CO2 f ;h þ EF CO2 f ;el  aÞ Ztot

e ¼ a  ðRel þ RTGC Þ bh refers to the fuel costs and taxes (energy tax (E) and CO2 tax) for the fuel used for heat generation. The shares (S) of the energy tax and CO2 tax charged depend on whether Ch calculation is for a HOB or a CHP plant (see footnote 4). Ztot is the total energy conversion efficiency of the plant. bel refers to the fuel costs for power generation in a CHP plant. a is the ratio between the power and heat generation. Since no energy tax or CO2 tax is charged for fuels used for power generation, these terms are zero. If the C h calculations concern a HOB, the whole term is zero (since a is zero for a HOB). g refers to the variable operation and maintenance cost for the plants. d refers to the cost of purchasing TEPs (depending on both the actual cost of the TEPs (C TEP ) and the CO2 emission factor (EF CO2 ) for the fuel used). e refers to the revenues from power and TGC sales in CHP plants. The input data used in calculation of C h for determination of the set of existing plants is found in the Appendix A. Fig. 1 illustrates a DH system as described in the HEATSPOT model. 2.2. Model application In the HEATSPOT model, 172 local DH systems, corresponding to 99% of the Swedish DH generation, are described system by system. In application of the HEATSPOT model, a dispatch order for the plants in a reference scenario is defined using the C h relation in Section 2.1. For the DH system illustrated in Fig. 1, industrial waste heat is

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calculated to have the lowest order of dispatch (lowest C h ), while the oil HOB unit is calculated to have the highest order of dispatch (highest C h ). The reference scenario in this analysis is that neither of the TGC and TEP schemes are applied, i.e. RTGC and C TEP in the C h relation are both zero. When the TGC and the TEP schemes apply in the other scenarios, the response of the model is to adjust the dispatch in order to maintain the lowest possible system cost. Plants that experience lower C h thanks to the changing inputs (e.g. bio fuelled CHP plants owing to revenues from TGC sales (RTGC )) are, hence, taken into operation to a greater extent than in the reference scenario and, conversely, plants that experience higher C h (e.g. fossil fuel HOBs owing to increased cost for CO2 emissions) are taken into operation to a lesser extent compared to the reference scenario.10 To simulate whether or not the TGC and TEP schemes increase the profitability of CHP investments, an iterative investment procedure was performed. CHP plants of different sizes (MW) were tested, one by one, in each DH system (in increments of 20 MWheat). This was done in all the scenarios (including the reference scenario). The plants tested were assigned an order of dispatch that corresponds to their relative C h . The annual system costs obtained for the different CHP investment alternatives were then compared.11 The CHP investment that gave the lowest annual system cost was regarded as being the most profitable. If the lowest system cost for a DH system was obtained without any CHP investment, the two trading schemes are regarded as not having changed the profitability for CHP investments in that system. The change in investment profitability is measured by comparing the size (in MW) of the most profitable investment in the alternative scenarios to the most profitable investment in the reference scenario. If it is larger in the alternative scenarios than in the reference scenario, the profitability is regarded as having increased. To investigate the resulting changes in the DH sector if all DH utilities actually invest in their most profitable CHP investment, the DH production from the CHP investment together with the change in DH production from the existing plants owing to the CHP investment (plants with higher order of dispatch than the CHP investment will produce less DH) were assessed. The changes in CHP generation and CO2 emissions were then recalculated through the power to heat ratios
(a) of the plants and the CO2 emission factors EF CO2 for the fuels used.

10 In the illustration in figure 1, the oil HOB is already the plant with the highest C h and therefore it cannot be taken into operation to a lesser extent. 11 The capital cost of the investments together with the sum of all plants C h multiplied by their respective annual operation time (no capital costs for existing plants are considered).

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2.3. Assumptions and data Two types of CHP plants were tested in order to determine the most profitable investment: wood fuel CHP and natural gas CHP. These two technologies were chosen since they are assumed to be the most profitable to invest in under the TGC and TEP schemes. Wood fuel CHP technology is a conventional steam cycle equipped with a flue gas condenser, while the natural gas CHP technology is a combined cycle. The technical and financial values used in the calculations are shown in Table 1, and are based on Elforsk (2003). An exchange rate of 9 SEK/h has been used in converting Swedish crowns (SEK) to Euro (h) here and throughout the analysis. (Table 1) It is assumed that CHP generation from a TGC eligible fuel is always associated with revenue from TGC sales (RTGC ). It is also assumed that generation from a TEPbound fuel is always associated with a cost for purchasing the TEPs (C TEP ).12 The Swedish power price level is assumed to be unaffected by the TGC scheme but to increase as an effect of the TEP scheme since the costs of marginal power generation determining European power prices will increase as an effect of the TEP scheme.13 The marginal power generation on the Nordic power market is in coal condensing plants with an efficiency of 35–40% (Bejgrowicz et al., 1999) and hence it is assumed that the power price will increase correspondingly.14 With the TEP scheme, the power price is assumed to consist of the sum of the power price independent of the TEP scheme and the increased cost in coal condensing plants owing to the TEP scheme. The power price independent of the TEP scheme is assumed to be 25.6 h/MWh for the intermediate time period in the model (March–May, Sept–Nov). This value corresponds approximately to the 2004 forward price for 2005 on the Nordic power exchange (Nord Pool, 2004). For the winter and summer periods in the model, the power price is assumed to be 20% higher and lower, respectively, than the intermediate period price.15 Regarding fuel prices, all fuels supplied to the DH systems are assumed to be available in unlimited volumes 12 TEP-bound fuels presently used in the Swedish DH sector are coal, oil, natural gas, LPG and peat (Swedish Environmental Protection Agency, 2004). For the period 2005–2007, the TEPs in Sweden are being distributed free of charge (Swedish Parliament, 2004). Independent of this free distribution scheme, generation based on a TEP-bound fuel is always associated with a variable cost since the possibility of selling the TEPs is missed. 13 The TGC, TEP, and power prices are probably interdependent (Unger and Ahlgren, 2005). 14 The emission factor for coal, 90.7 gCO2/MJfuel (see Appendix) and a 35% conversion efficiency for coal condensing plants gives an increased power prices of 9.3 and 18.6 h/MWh for the TEP prices 10 and 20 h/tCO2, respectively. 15 During the years from 1996 to 2002, the average winter (Dec–Feb) spot price on Nord Pool, was about 20% higher than the annual average price, while the average summer (Jun–Aug) price was about 20% lower than the annual average price.

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Table 1 Technical and financial data used in the model for the optional CHP investments Technology

Wood fuel CHP

Natural gas CHP

Size MWel

10–20

21–50

51-

20–90

91-

Total efficiency, Ztot (based on lower calorific value) Power-to-heat ratio, a Fixed O&M cost, % of investment Investment cost, kh/MWel Rate of return, % Economic lifetime, years

1 10 0.32 2 2356 6 20

1 10 0.37 2 1822 6 20

1 10 0.46 2 1333 6 20

0 89 1.00 2 889 6 20

0 90 1.20 2 722 6 20

Table 2 Fuel prices and taxes used Fuel

Waste Biogas Industrial waste heat Tall-oil pitch Peat Wood fuels Coal LPG Natural gas Oil Electricity

Price (h/MWhfuel)

1.7 (SEA, 2004) 4.4 (SCB, 2004) 5.6a 9.4 (SCB, 2004) 13.3 (SEA, 2004) 15.6 (SEA, 2004) 4.8 (SEA, 2004) 26.7 (SCB, 2004) 12.6 (SEA, 2004) 14.1 (SEA, 2004) See Table 3

Energy tax for heat

CO2 tax for heat

generation (h/MWhfuel)

generation (h/MWhfuel)

0 0 0 0 0 0 4.7 1.2 2.7 7.6 26.8

0 0 0 0 0 0 34.2 16.3 21.7 27.0 0

The price has therefore been set in order to allot the supply of industrial waste heat to a position in the dispatch order common today, i.e. a higher order of dispatch than waste fuel based technologies only. a The price of industrial waste heat could not be found in the statistics.

and at constant prices shown in Table 2.16 The fuel prices and taxes used are also assumed to be identical for all DH systems. The fuel prices are based on forecasts and statistics from SEA (2004) and Statistics Sweden (SCB, 2003). The tax rates are those applying from January 1, 2004 (Swedish National Tax Board (Skatteverket), 2004). (Table 2) The annual DH generation volume is assumed to be constant throughout the analysis, 52.3 TWh/year. This corresponds to the sum of the heat volumes generated by all the DH systems affiliated with the SDHA in 2002, adjusted to a normal climate year.17 Conversion efficiencies, power-to-heat ratios, variable operation and main16 The only exception from this is natural gas, which is an optional fuel only in the DH systems along the existing natural gas grid (natural gas in presently available only along the Swedish west coast). The profitability for natural gas CHP investments was therefore tested in this geographical area only. 17 The demand for DH has increased steadily in recent years and is expected to increase further, by some 2-3% annually (SDHA, 2004). Since the HEATSPOT model describes each DH system and there are difficulties in deciding which of the DH systems that will be expanded, this factor has been excluded.

tenance costs and CO2 emission factors used for the existing plants are tabled in the Appendix A. 2.4. Scenarios analysed The analysis includes three scenarios in which the TGC and the TEP schemes together with the CO2 tax are applied to varying extents. The model results for the different scenarios are compared with the model results for a reference scenario where the CO2 tax but neither of the trading schemes is applied.





In the first scenario, denoted ‘‘(1) TGC’’, the effects of the TGC scheme in isolation were investigated. Two prices of TGCs were tested, 10 and 20 h/MWhel, and the CO2 tax was applied. This scenario represents the situation without extension of the TEP scheme beyond 2008–2012. In the second scenario, denoted ‘‘(2) TGC & TEP’’, the effects of co-existence of the TGC and TEP schemes were investigated. Two prices of TGCs, 10 and 20 h/ MWhel, in combination with two prices of TEPs, 10 and 20 h/tCO2 were tested. The CO2 tax was also applied in

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Table 3 Overview of the variables in the scenarios Scenario

TGC price (h/MWhel)

TEP price (h/tCO2)

Electricity price winter/ intermediate and/summer periods (h/MWh)

Reference (no trade) (1)TGC

— 10 20 10 10 20 20 10 10 20 20

— — — 10 20 10 20 10 20 10 20

30.7/25.6/20.4 30.7/25.6/20.5 30.7/25.6/20.6 40.0/34.9/29.7 49.3/44.2/39.0 40.0/34.9/29.7 49.3/44.2/39.0 40.0/34.9/29.7 49.3/44.2/39.0 40.0/34.9/29.7 49.3/44.2/39.0

(2) TGC & TEP

(3) TGC & TEP no tax

CO2 tax for heat generation

Applied Applied Applied Applied Applied Applied Abolished Abolished Abolished Abolished

Table 4 Most profitable CHP investments in the Swedish DH sector in the scenarios according to the model Scenario

TGC price (h/MWhel)

TEP price (h/tCO2)

Investments wood fuel CHP (GWel)

Investments natural gas CHP (GWel)

Reference (no trade) (1)TGC

— 10 20 10 10 20 20 10 10 20 20

— — — 10 20 10 20 10 20 10 20

0.5 1.0 1.5 1.4 1.6 2.1 2.6 0.8 1.3 1.4 1.9

0.4 0.1 0.1 0.3 1.3 0.1 0.2 1.0 1.4 0.4 1.4

(2) TGC & TEP

(3) TGC & TEP no tax



this scenario. This scenario represents the situation with extension of the TEP scheme beyond 2008–2012, and with the current CO2 tax retained. In the third scenario, denoted ‘‘(3) TGC & TEP no tax’’, the effects of co-existence of the TGC and the TEP scheme together with abolition of the CO2 tax were investigated. The same combinations of TGC and TEP price as in the second scenario were tested also in this scenario. This scenario represents the situation with extension of the TEP scheme beyond 2008–2012, and with abolition of the current CO2 tax.

No scenario was drawn up to investigate the effects of the TEP scheme in isolation since it is assumed that the TGC scheme will endure for many years. The future existence of the TEP scheme is regarded as more uncertain.18 We draw up Scenarios 2 and 3 both with 18 Discussions are ongoing in Sweden on postponing the current expiry year of the TGC scheme from 2010 to 2030. Potential post-Kyoto agreement beyond 2012 is regarded to be much more uncertain since it likely to depend largely on the costs of achieving the targets of the first commitment period, 2008–2012.

and without the CO2 tax because of the current Swedish debate, related to the TEP scheme introduction, on whether or not to preserve the CO2 tax. Table 3 gives an overview of the variables in the scenarios. (Table 3) 3. Results This chapter presents the results of the model regarding the profitability of investments in new CHP plants in the Swedish DH sector after the introduction of the TGC and TEP schemes. The implications for CHP generation, CO2 emissions and system costs of implementing the CHP investments are also presented. 3.1. Profitability of CHP investments The results of the analysis regarding the most profitable CHP investments are presented in Table 4. As seen from the table, the most profitable CHP investment varies between the scenarios. The TGC scheme will increase the profitability of investments in CHP plants based on TGCeligible fuels, e.g. wood fuels, since such plants will become

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TGC10

TGC10/TEP20

TGC20/TEP10

TGC20

TGC20/TEP10

TGC20/TEP20

TGC10/TEP10

TGC20/TEP20

TGC10

TGC10/TEP20

TGC20 TGC10/TEP10

10

25

5

20

Swedish DH sector (gross) 0 Mton/year

TWh/year

Total CHP 15

10

Renewable CHP

-5

-10 Swedish DH sector (net)

5

-15

-20

0 Reference (no trade)

(1) TGC

(2) TGC & TEP

(3) TGC & TEP no tax

Fig. 2. Total and renewable annual power generation in existing and new CHP plants in the DH sector according to the scenarios.

more profitable to operate. The profitability will increase with increasing TGC prices. The increased profitability of wood fuel CHP plants reduces the relative profitability of investment in other technologies, e.g. natural gas CHP. Co-existence of the TGC and the TEP schemes increases the profitability of wood fuel CHP additionally, owing to the power price increase assumption associated with the TEP scheme. The change in the profitability of natural gas CHP with the TEP scheme is less certain since increased power price and purchases of TEPs counteract the heatgenerating cost (C h ), as shown in Section 2.1. Abolition of the CO2 tax enhances the economics for investments in plants based on fossil fuels, such as natural gas CHP. The increased profitability of natural gas CHP in this scenario analogously reduces the relative profitability of investment in wood fuel CHP. (Table 4) In Table 4, it is shown that profitable investments of 0.5 and 0.4 GWel for wood fuel CHP and natural gas CHP, respectively, could be made by the DH utilities in the reference scenario.19 The greatest profitability for wood fuel CHP (2.6 GWel) is obtained in scenario (2), with TGC and TEP price combinations of 20 h/MWhel and 20 h/tCO2 (TGC20/TEP20). This is thanks to the major revenues from TGC and power sales coupled with the operation of wood fuel CHP in this scenario. The most profitable investments in natural gas CHP are obtained in the scenarios with the price combinations TGC10/TEP20 (also for TGC20/TEP20 if the CO2 tax is abolished). This is owing to the large power price increase assumed for TEP20 (see Table 3), and the large power generation capability 19 The installed power generation capacity in the DH sector 2002–12-31 amounted to about 2.5 GW (Nordel, 2004).

Reference (no trade)

(1) TGC

(2) TGC & TEP

(3) TGC & TEP no tax

Fig. 3. CO2 emissions from the DH sector in the scenarios. Gross accounts for the CO2 emissions generated in the DH sector only, while net emissions include avoidance of CO2 emissions in coal condensing plants owing to increased Swedish CHP generation.

(large power-to-heat ratio, see Table 1) in relation to the relatively low CO2 emissions for the natural gas CHP investment option. 3.2. Power generation in CHP plants Operation of the CHP plants in Table 4 together with the change in operation time for existing CHP plants (caused by changed dispatch order), increases the power generation volume from the DH sector. Fig. 2 illustrates the total (sum of fossil and renewable) and renewable annual power generation in new and existing CHP plants in the scenarios. The figure shows that the annual total power generation volume in the DH sector could amount to between 13 TWh (Reference scenario) and 24 TWh (Scenario 3, TGC20/ TEP20). The large figure in Scenario 3 is a result of the large profitability and the high power to heat ratio for the natural gas CHP investment in this scenario. The annual renewable power generation could amount to between 5 TWh and 17 TWh.20 3.3. CO2 emissions Operation of the CHP plants in Table 4 together with the change in operation time for existing technologies also changes fuel consumption, which, in turn, changes the CO2 20 The total power generation from CHP plants in the DH sector was 6.6 TWh between August 03 and July 04 (Statistics Sweden, 2004b). The renewable power generation in these plants amounted to about 1.2 TWh in 2002 (Author’s calculation based on SDHA (2003)).

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System cost

TEP cost

Fuel cost

Revenue from TGC sales (in CHP plants based on renewable fuels) Revenue from power sales (in CHP plants)

Capital cost CO2 tax 1200 1000 800 600

M year

400 200 0 -200 -400

the installations of natural gas CHP plants and increased economics of existing fossil fuel based plants result in no or only moderate CO2 emissions reductions as compared with the reference scenario. In this scenario, coal once again becomes the most profitable fuel to use in existing CHP plants with coal/wood fuel flexibility (with the exception of TGC20/TEP20). Net CO2 emissions decrease significantly in all scenarios. The largest decrease is seen in the scenarios with the largest volume of total CHP generation since large volumes of coal condensing power are then avoided. The net CO2 emissions are also virtually independent of the investment ratio between the two technologies, since the CO2 emissions generated in natural gas CHP are compensated for by the higher power-to-heat ratio and thus a larger replacement of coal condensing power generation in relation to wood fuel CHP. However, this is only true under the conditions that coal condensing is the marginal source of power (see e.g. Werner, 2001). 3.4. System costs

-600 -800

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Reference (no trade)

(1) TGC

(2) TGC & TEP

(3) TGC & TEP no tax

Fig. 4. Annual system costs and the different parts according to the scenarios for a TGC price of 20 h/MWh and a TEP price of 10 h/tCO2. Cost parts with minor impact on the system cost were excluded from the figure.

emissions. Figure 3 illustrates these changes in terms of gross and net emissions from the DH sector. The gross emissions account only for CO2 emissions related to fuel usage in the DH sector, while the net CO2 emissions also take into account the change in emissions from marginal power generation (which is assumed to be coal condensing, see Section 2.3).21 The reduction of gross CO2 emissions in scenario (1) is mainly attributable to the increased profitability of wood fuel CHP investments, at the expense of natural gas CHP, as compared to the reference scenario. Fuel consumption in existing oil and coal and, to some extent, waste-based plants is also reduced as a consequence of reduced operation times. In scenario (2), the main reason for gross CO2 reductions is fuel switches from coal to wood fuel that become profitable in this scenario in existing CHP plants with such fuel flexibility. The use of oil and waste fuel is also reduced additionally. Peat consumption is also reduced in this scenario, owing to the TEP-obligation. The small CO2 reduction for the price combination TGC10/TEP20 in scenario (2) is a result of the large natural gas CHP installations (see Table 4). In scenario (3), 21 The net CO2 emissions are defined as gross CO2 emissions minus avoided CO2 emissions in coal condensing plants acquired from power generation surplus (CHP generation minus power consumption in heat pumps and electric HOBs) in the DH sector.

Fig. 3. The total costs for the investments, listed in Table 4, are in the range of 1.3 billion h (Reference scenario) and 4.1 billion h (Scenario (2) TGC20/TEP20). Fig. 4 illustrates the annual system cost and its different parts for the price combination TGC20/TEP10.22 Fig. 4 shows that fuel costs increase with capital costs. The reason is that about 1.5-2 times more fuel is used in a CHP plant as compared with an HOB for the same amount of heat generated. Another reason is the fuel price assumptions, shown in Table 2, which makes wood fuel more costly to use than most other fuels (the scenario illustrated in Fig. 4 is dominated by investments in wood fuel CHP). In spite of increased capital and fuel costs, the system costs decrease. The main factors for this are the increased incomes from power and TGC sales (negative costs in Fig. 4). The increased use of wood fuels in scenarios (1) and (2) also reduces the CO2 tax component. In scenario (3), when the CO2 tax is abolished, the CO2 tax component is, accordingly, zero. 4. Discussion The results above showed that the two trading schemes significantly increase the profitability of investments in new CHP plants in the Swedish DH sector. It was also shown that investments in such plants would lead to great increase in power generation and decrease in CO2 emissions. The results may, however, depend to some extent on the assumptions made, for example regarding fuel prices, TGC and TEP prices and the relation between TEP price and 22 These price levels are considered to be the most likely of the ones tested according to statistics from SVK (2005) and the forecast made in ECON (2004). The trends in the cost curves for the other tested combinations of TGC and TEP price are similar to those shown in Fig. 4.

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power price. Possible implications of variations of the assumed parameters on the results are discussed below. The prices of wood fuel and natural gas may increase compared to the prices used in this study since the demand for renewable and carbon-lean fuels is likely to increase when many countries attempt to comply with their CO2 reduction commitments undertaken in the Kyoto protocol. The natural gas price may, on the other hand, also decrease, owing to the resulting increased competition between suppliers from the ongoing deregulation process of the EU natural gas markets (European Parliament, 2003a). The future cost of using oil and coal, is, however, always likely to be higher than the cost of using wood fuels and natural gas, owing to their higher carbon contents. The profitability of wood fuel and natural gas CHP investments in relation to other investment options is, therefore, regarded to be fairly independent of future changes in wood fuel and natural gas prices, although the system costs shown in Figure 4 will increase with increasing fuel prices. The levels of TGC price tested in the analysis (10 and 20 h/MWhel) were of the same order of magnitude as indicated in SOU (2001). According to recent statistics these prices are low since the actual average TGC price between 2004-09-08 and 2005-09-08 was 25.5 h/MWhel (SVK (Svenska kraftna¨t), 2005). A scenario with a TGC price of 25.5 h/MWhel would probably have resulted in even larger profitability of wood fuel CHP investments than shown for the tested TGC prices. The two TEP prices tested in the analysis (10 and 20 h/tCO2) covered the interval regarded as probable in the short term (see e.g. ECON (2004)). These prices are also low as compared with the actual average TEP price between 2005-08-09 and 200509-19 which was about 23.5 h/tCO2 (Nord Pool, 2005). The assumed correlation between the TEP price and the Swedish power price is likely to have a major impact on the profitability of investments in new CHP plants in scenario (2) and (3). In this study, it was assumed that the increase in Swedish power prices owing to the TEP scheme is directly dependent on the increased marginal generation costs in European coal condensing plants. This is a larger cost increase than what was found in ECON (2004). In that study, the increase in Nordic power prices was expected to be somewhat lower than the increased marginal cost of coal condensing power in the short term owing to lack of power transmission capacity between Sweden and neighbouring countries. How the TEP scheme actually has affected the Swedish power price during the first months (2005-01-01 to 2005-09-20) in force is difficult to determine. Assumptions in this study regarding lower power price increases owing to the TEP scheme would probably have reduced the profitability of both wood fuel and natural gas-based CHP investments. Moreover, only two different investment alternatives were considered, wood fuel and natural gas CHP. Locally, there could, of course, be more profitable investment alternatives than these, for example connecting the DH

grid to a nearby industry to makes use of their waste heat, or investing in a waste incineration plant with heat recovery. In fact, many utilities are currently building or considering building waste incineration plants connected to the DH grid (see e.g. Sahlin et al., 2004). Such investments are, however, considered primarily to have been triggered by other factors than the introductions of the TGC and TEP schemes and are, therefore, not considered here. Compared with SOU (2001), Unger and Ahlgren (2005), and Hindsberger et al. (2003), the profitability of new investments in CHP generation in the Swedish DH sector is found to be greater in this study. One explanation for this can be that these studies cover the entire energy system, meaning that other investment options in other parts of the energy system perhaps were considered more profitable than investments in the Swedish DH sector. Judgements like that are, on the other hand, difficult to make in models such as the ones used in the studies above since they only include rough descriptions of the subsectors included. Compared with Profu (2003), the outcome of this study showed an increased profitability of CHP investments correspondent to more than doubled power generation volume. Probable explanations to these differences are that the demands of profitability of investment were higher in the Profu study making investments less profitable as compared with our study. The Profu study also considered more options for investment than wood fuel CHP and natural gas CHP meaning the other investment alternatives perhaps were found more profitable. The level of aggregation of the DH systems is also likely to be an important source for the differences between the studies.

5. Conclusions The aim of this study was to analyse the changes in profitability of CHP investment in the Swedish DH sector owing to the introductions of the TGC and TEP schemes. Another aim was to analyse the changes in CHP generation, CO2 emissions, and operation costs if the CHP plant shown to be most profitable in each system is actually invested in. The study shows that the TGC and the TEP schemes have increased the profitability of investments in new CHP plants in the Swedish DH sector significantly. The TGC system alone doubles the profitability of wood fuel CHP investments at a TGC price of 10 h/MWhel, and triples it at a TGC price of 20 h/MWhel. The TEP scheme additionally enhances the profitability of investments in wood fuel CHP plants, owing to the assumption made of higher power prices as an effect of the TEP scheme. The increased profitability of wood fuel CHP investment from the TEP scheme is reduced, to the benefit of natural gas CHP investments, if the CO2 tax is abolished. Abolition of the CO2 tax is, however, crucial if competition between wood fuel and natural gas CHP investments is to be maintained at all.

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If all DH utilities undertook their most profitable investment according to this study the result would be large volumes of additional power generation in Sweden. This would, in turn, result in CO2 emission reductions of up to 13 Mton/year in the European power generation sector, assuming that coal-condense based power generation emitting more CO2 would be displaced.

Acknowledgements The authors are grateful for the financial support allocated to the Nordleden-project, in which the HEATSPOT model was developed. The Nordleden-project was a multidisciplinary Nordic energy systems analysis project. The main funding for this project was provided by the Swedish Energy Agency, the Swedish District Heating Association, the Swedish Bioenergy Association and the Swedish Natural Gas Association. The valuable comments of an anonymous reviewer are also gratefully acknowledged.

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Appendix A The fuel costs values used (C f ) used for determination of the heat generating cost (C h ) in the construction of the HEATSPOT model correspond to the total annual purchase value divided by the total annual use of each fuel in the DH sector (Statistics Sweden, 2000, 2001, 2002, 2003). The power prices used (C f for heat pumps and electric HOBs and Rel ) are annual averages of the spot prices on the Nordic power exchange for 1999–2002 (Nord Pool, 2003). The figures used for taxes (TaxE and TaxCO2) are based on statistics from the Swedish National Tax Board (2004). Fuel prices, power prices, and taxes used in the analysis are presented in Section 2.3. The total efficiency (Ztot ), power-to-heat ratio (a) and variable operation and maintenance cost (CO&Mv) used are estimates of national averages, since no reliable statistics are available. The CO2 emission factors used were collected from the Swedish Environmental Protection Agency (2003). The values of those parameters are shown in the table below. These values are used both in the construction of the model as well as in the analysis.

Fuel/Technology

Total efficiency, Ztot (based on lower calorific value)

Power-to-heat ratio, a

Variable O&M cost, CO&Mv (h/MWhfuel)

CO2-emission factor, EFCO2 (g/MJfuel)

Waste CHP/HOB Peat CHP/HOB Coal CHP/HOB Co-fired coal/wood fuel CHP Wood fuels CHP/HOB Tal oil pitch CHP/HOB Oil CHP/HOB Bio gas CHP/HOB LPG CHP/HOB Natural gas CHPCCGT/CHPCONV/HOB Industrial waste heat Heat pump Electric HOB

0.85/0.85 0.85/0.85 0.85/0.85 0.85 1.05/1.05 0.90/0.90 0.90/0.90 0.90/0.90 0.90/0.90 0.90/0.90/0.90 1.00 3.00 (COP) 1.00

0.25/0.00 0.40/0.00 0.40/0.00 0.40 0.40/0.00 0.50/0.00 0.50/0.00 0.50/0.00 0.50/0.00 1.10/0.50/0.00 0.00 0.00 0.00

8.3/6.7 2.6/2.0 3.3/2.7 3.3 2.6/2.0 0.9/0.7 0.9/0.7 0.9/0.7 0.9/0.7 0.9/0.9/0.7 0.0 0.7 0.2

32.7 107.3 90.7 90.7/0.0 0.0 0.0 76.2 0.0 65.1a 56.5 0.0 0.0b 0.0b

a

Emission coefficient for propane used. The system boundary in the analysis is set around the DH sector. Consequently, only the net exchange of electricity between the DH sector and its surroundings has an impact on the CO2 emissions from electricity generation outside the DH sector. Electricity consumption in heat pumps and electric HOBs is assumed to derive from CHP generation within the DH sector and was therefore set to zero, since emissions from CHP generation are already accounted for. b

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