£ ECONOMIC COSTS OF ELECTRICITY PRODUCTION IN POLAND M. BEELDMAM J. SOLINSKI IWjWIWI * m BOOUKNT IS UIUMITEO nun* SAianiMTEf The Netherlands Energy Research Foundation ECM Het Energieonderzoek Centrum Nederland (ECN) is is the leading institute in the Netherlands for energy het centrale instituut voor onderzoek op energie research. ECN carries out basic and applied research gebied in Nederland. ECN verricht fundamenteel en in the fields of nuclear energy, fossil fuels, renewable toegepast onderzoek op het gebied van kernenergie, energy sources, policy studies, environmental aspects fossiele-energiedragers. duurzame energie, beleids of energy supply and the development and application studies, milieuaspecten van de energievoorziening en of new materials. de ontwikkeling en toepassing van nieuwe materialen. ECN employs more than 900 staff. Contracts are Bij ECN zijn ruim 900 medewerkers werkzaam. 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Box I Postbus I NL-I755ZG Petten I755ZG Petten the Netherlands Telefoon : (02246) 49 49 Telephone : +31 2246 49 49 Fax : (02246) 44 80 Fax : +31 2246 44 80 Dit rapport is te verkrijgen door het overmaken van This report is available on remittance of Dfl. 35 to: f35.-- op girorekening 3977703 ten name van: ECN, General Services. ECN, Algemene Diensten Petten, the Netherlands te Petten Postbank account No. 3977703. onder vermelding van het rapportnummer. Please quote the report number. © Netherlands Energy Research Foundation ECN © Energieonderzoek Centrum Nederland FEBRUARY 1994 ECN-C-94-009 ECONOMIC COSTS OF ELECTRICITY PRODUCTION IN POLAND M.BEELDMAN J.SOUNSKI MASTER mrnwmi IF OK MoivEir i nmm «lift mnini On Framework of the study This study was conducted within the framework of a co-operation between the Netherlands Energy Research Foundation (ECN), Petten, the Nether lands, and Instytut Energetyki (IEn), Warsaw. Poland. The authors thank the staff of the System Development Department. [En, and the staff of ECN Policy Studies for their valuable contributions to this study. Abstract In Poland the process of transition from a centrally planned economy to wards a more market oriented economy started in 1990. Subsidies were gradually abolished, and prices are expected to reach the Western Euro pean level in the near future. Therefore, the current costs and accounting method cannot be used for a proper economic appraisal and the concept of real costs must be applied. In power stations the economic costs for fuel and depreciation should be taken into account, which is very important to estimate the expected future costs, price level of electric energy, and the general economic situation of the electricity sub-sector up to the year 2000. This study presents a methodology for the calculation of the economic costs of the production of electricity. This methodology is applied to assess electricity production cost in Poland by type of power station for the years 1995 and 2000. In addition, an overview is presented of the methods used by the OECD countries, particularly in the Netherlands. The main conclusions of the study are: 1) the real economic costs to gen erate electricity in Poland are about two times higher compared with the traditional book-keeping data; 2) the investment costs will become the most important cost component in the near future; and 3) there are con siderable differences in production cost per kWh for the different types of power plants in Poland. Keywords ECONOMIC COSTS POWER SYSTEM DEVELOPMENT ELECTRICITY PRODUCTION 2. ECN-C -94-009 CONTENTS 1. INTRODUCTION 5 1.1 Background 5 1.2 Objectives of the study 6 2. POLISH POWER SYSTEM DEVELOPMENT 7 3. CALCULATION OF ECONOMIC PRODUCTION COSTS 9 3.1 Classification of production costs by type of power station 9 3.2 Calculation schemes of production costs for different types of power plants 9 3.2.1 Cost components 9 3.2.2 Calculation units 10 33 Calculation schemes of power system production costs 11 4. ELECTRICITY PRODUCTION COSTS IN OECD COUNTRIES 13 4.1 Costs for the design and extension of a power system 13 4.2 Cost allocation for an existing system 14 4.3 Economic parameters used in different countries 17 5. COST ASSESSMENT FOR PLANNING PURPOSES 19 6. POLISH ELECTRICITY PRODUCTION COSTS FORECASTS FOR 1995 AND 2000 21 6.1 Future system development in Poland 21 6.2 Assumptions 21 6.3 Forecasts of electricity production costs 23 6.4 Forecasts for the costs of the power system 26 7. CONCLUSIONS 27 REFERENCES 29 APPENDIX A. Levelized costs sensitivity analysis 31 APPENDIX B. Costs of power and heat in CHP plants 35 APPENDIX C. Simulation of electricity producing units 37 APPENDIX D. Production per unit in 2000 45 ECN-C-94-009 3 ECM-C--94-009 1. INTRODUCTION 1.1 Background Poland is a medium size country. The area is 312.700 sqJun and the popu lation is over 38 million. The population density is 122 inhabitants per sqJtm. Poland has rich primary energy resources, but they are mainly solid fuels: hard coal and lignite. Natural gas resources are relatively small and crude oil insignificant. Hydroelectric potential is also low. There are no uranium deposits. Therefore hard coal is one of the most abundant natural resources, playing the essential role in the Polish economy. During last years over 95% of primary energy production were coal and lignite, and about 75% of primary energy consumption. Hard coal is the country's leading export product. The Polish economy is presently undergoing a period of transition towards a more market oriented economy. In September 1989, the Polish Govern ment launched a cra^h programme of macroeconomic reforms to curb the huge inflation rates and to reduce foreign debt. The crash programme resulted in a decline of industrial production by more than 40% and. conse quently, primary energy demand fell from 127 Mtoe in 1988 to 97 Mtoe in 1992. The current energy situation in Poland is characterized by: - Excessive dependence on coal and an unfavourable structure of primary energy supply. The liquid fuels per capita consumption is 3 to 4 times lower than in Western European countries. • High dependence on the formei USSR for imports of natural gas and crude oil. In 1992 about 65% of natural gas came from the former USSR. - High energy intensity of the economy (at least two times higher than in OECD countries) and a relatively low per capita energy consumption, approximately 2.5 toe. - Unfavourable trends in energy foreign trade balance. From a substantial exporter of primary energy in the past, Poland became a net importer. In financial value, hydrocarbon imports exceed considerably the decreasing coal exports. - Serious environmental degradation. High energy intensity and excessive coal use cause serious environmental problems, in particular air pollution. - Low energy prices, which are still below economic cost level (particularly prices of electricity) and do not reflect full social costs. The economic reform affects the electricity subsector and the cost of electricity produc tion. In Poland the process of transition from a centrally planned economy to wards a more market oriented economy started in 1990. Subsidies were gradually abolished, and prices are expected to reach the Western European level in the near future. Therefore, the current costs and accoun ting method cannot be used for a proper economic appraisal and the con cept of real costs must be applied. In power stations the economic costs for fuel and depreciation should be taken into account, which is very important ECN-C-94-009 5 to estimate the expected future costs, price level of electric energy, and the general economic situation of the electricity sub-sector up to 2000. 12 Objectives of the study The main objectives of the study are as follows: - to present general data on the Polish electricity subsector. - to assess the economic costs of electricity production for different types of the Polish power plants, - to asses the system costs for production of electricity. The assessment of economic costs serves several purposes. Firstly, in de signing a power system it is necessary to assess these costs in order to establish a power system with the lowest total costs and a cost assessment method cen give a quick insight into the consequences of changing certain parameters; and secondly, the assessment of economic costs relates to the management and operation of a system. This concerns decisions on which power stations are to produce electricity and which costs should be paid by which customers. This study deals with both objectives, although no translation is made from electricity production costs into end user tariffs. The currency used in this report is US dollars unless stated otherwise. The study has been conducted jointly by the Institute of Power Engineering, Warsaw and by Netherlands Energy Research Foundation. Petten. The study consisted of three phases: I. Formulation of methods to calculate the costs of electricity production and discussing these methods during a meeting in Petten. II. Calculation of the 'economic costs' of electricity production for dif ferent types of Polish power plants and a forecast of the system pro duction costs for the years 1995 and 2000. Discussion of the results of the study during a meeting in Warsaw. III. Preparation of final report. ECN-C-94-009 2. POLISH POWER SYSTEM DEVELOPMENT During the last four decades, in particular during the period 1970-1989. the Polish power system developed very rapidly. At present total public electri city capacity comprises 55 thermal power plants. 5 pumping-storage plants and more than 100 small hydro-electric plants. The largest thermal station is Belchatow 4320 MW (12 x 360 MW), lignite fired. The largest hydro-electric plant is the pump-storage plant Xamowiec 680 MW. In 1992 the installed capacity of power stations amounted 32.2 GW and the electricity production amounted 132.7 GWh. Electricity is produced mainly by thermal power plants (97%). There is no nuclear power plant in Poland. The main part of the transmission system is formed by the 400 kV lines, supplemented with 220 kV lines. There is also a 750 kV connection with the former USSR. The distribution network operates at 110, 30, 20, 15 and 6 kV, but also at low voltages. The general data on the development of the electricity sector are shown in table 2.1. Table 2.1 General data on the development of the electricity sector 1970-1992 Spectfication Units of measure 1970 1980 1990 1991 1992 1. Installed capacity GW 13.9 25.3 32.0 32.1 32.2 of this: hard coal 6.9 16.2 17.8 17.9 17.9 lignite 4.0 4.8 9.1 9.1 9.1 hydro 0.8 1.3 2.0 2.0 2.0 autoproducers 2.2 3.0 3.1 3.1 3.2 2. Peak demand GW 10.7 20.3 23.4 22.7 21.5 3. Gross electricity production TWh 64.5 121.9 136.4 134.7 132.7 of this: public power plants 56.0 111.5 128.2 126.8 124.6 in that: hard coal r 72.3 70.1 68.8 lignite - • 52.0 52.7 51.6 4. Cross electricity production per capita kWh/c 1984 3425 3577 3516 3460 5. Electricity import TWh 1.6 4.2 10.4 6.7 5.0 6. Electricity export TWh 1.5 4.4 11.5 9.3 9.1 7. Fuels consumption of this: hard coal Mt 19.6 45.9 36.0 33.5 31.6 lignite Mt 26.4 33.1 65.8 66.4 64.0 3 natural gas Mm 454 8 3 3 r liquid fuels kt 324 636 148 216 • 6. Specific fuel consumption kJ/kWh 11460 10610 10000 9960 9880 9. Electric lines 1000 km 110-750 kV 23 43 43 43 44 15- 60kV 169 226 259 262 265 low voltages 245 313 355 355 362 Source: (2,3| The climatic conditions were the main reason for a significant development of district heating during the past decades. At present the 50 largest Polish cities are supplied with heat through a district heating system from public ECN-C-94-009 7 CHP stations. The production of heat in 1992 amounted to 202 PJ, of which 149 was supplied from co-generation. The development of the ca pacity of the public CHP and heat production during the period 1970-1992 is presented in table 2.2. Table 2.2 General data on the public CHP 1970-1992 Spetification Units of measure 1970 1980 1990 1991 1992 1. Available thermal power GWt 7.7 20.0 26.5 27.3 27.9 2. Heat production PJ 75.9 216.8 235.0 215.3 201.8 55.1 125.1 141.5 146.3 148.7 separately produced 20.8 91.7 93.5 69.0 53.1 of this: heating boilers 52.9 67.0 42.6 31.3 3. Fuels consumption of this: hard coal Mt 4.7 13.1 11.6 13.3 10.6 lignite Mt 0.2 0.6 0.6 0.6 0.7 natural gas Mm 148 20 6 5 liquid fuels kt 10 354 255 220 4. Specie fuel consumption MJ/GJ 1260 1225 1215 1210 1204 Source: [2,3] 8 ECN-C-94-009 3. CALCULATION OF ECONOMIC PRODUCTION COSTS The economic costs of electricity production are assessed for financial management of power plants and power system. The methodology descrip- ted in this chapter is based on the principles of accounting methods used by the Polish power plants. 3.1 Classification of production costs by type of power station The production costs by types of power stations are given in table 3.1. including the future technologies to be applied in Poland up to 2010. Table 3.1 Production costs by types of power stations pe of power station Symbol Thermal power stations and CHP plants K 1.1. Hard coal power station "Ï 12. Lignite power station •S 1.3. Gas power station K* 1.4. Nuclear power station K£ 1.5, Combined Heat and Power (CHP plants) K^ Hydro-power stations K 2.1. Pump-storage power stations K* 2.2. Run-of-river power stations Kf Total production costs K« 3.2 Calculation schemes of production costs for different types of power plants 3.2.1 Cost components The costs components for several types of power stations are given in table 3.2. 9 Table 3-2 Calculation schemes by types of power stations Thermal-Power and CHP plants Pump-Storage power stations Run-of-River power stations 1. Variable costs 1. Variable costs a. Fuel b. Fuel purchase Electrical energy c. Chemicals and for pumping water preparation d. Environmental protection 2. Fixed costs 2. Fixed costs 2. Fixed costs a. Wages and surcharges a. Wages and surcharges a. Wages and surcharges b. Depreciation b. Depreciation b. Depreciation c. R&M c. R&M c. R&M d. Other costs d. Other costs d. Other costs e. Interest e. Interest e. Interest R&M « Repairs and Maintenance The production costs are usually divided into two components: the variable costs related to the amount of electricity produced (in MWh) and fixed costs related to the installed capacity (MW). The variable costs include: a. fuel costs (hard coal, lignite, nuclear fuel, liquid fuels); b. fuel purchase, mostly fuel transportation and storage costs, including loading; c. chemicals and water preparation, including mostly all costs of tech nological water preparation; d. environmental protection, duties and eventual fines related to the utiliz ation of the environment; e. electrical energy for water pumping from the lower to the upper basin. The fixed costs include: a. salaries and surcharges, including wages, salaries, taxes related to sal aries, social insurance costs, labor fund; b. depreciation is calculated from fixed assets, equipment, legal and im material values; c. R&M costs are mostly costs of repairs, maintenance and reconditioning of stations equipment; d. others costs; e. interest costs. These are costs of investment credits. 3.2.2 Calculation units The costs are presented as per unit values in order to be able to compare the costs of the different types of power plants. a. The variable costs are related to electricity or heat output net at the power station terminal i.e. per MWh of electricity or per GJ of heat. 10 ECN-C-94-009 Calculation of economic production costs b. Fixed costs are related to produced electricity (MWh) and to installed capacity (MW). Table 3.3 Formulas to calculate per unit generation costs per MWh Thermal power Pump-storage Run-of-River 6 CHP plants Power Stations Power Stations l gv hp_ gv Variable k - k — gv t AA gV AhP g g Khp „hf h Variable kl = gf khP_ V k ï= V gf gf hf V gf AhP AA g g g 1 h „hf , K . K P K Variable khp- 8 khf_ g g 1 g h g hf A A P A g g A g where: k - per unit costs, K - absolute costs, A - electricity output, indexes - as in table 3.1. CHP plants (Combined Heat and Power production) produce both electricity and heat and therefore the production cost must be divided between these two products. A brief explanation of the method used for costs separation is given in the appendix B. The fixed costs per MW installed in a specific year are important for many purposes. The formulas are given in table 3.3. Table 3.4 Formulas to calculate fixed costs per MW installed Thermal power & CHP plants Pump-storage Power Stations Run-of-River Power Stations hp „hf K hf kl = -Jl khp_ _gf k -_£ P pt P php P phf where: P - is the installed capacity in MW f • fixed costs. 3.3 Calculation schemes of power system production costs Electricity production costs for national power system are the sum of pro duction costs of all participating power stations minus own consumption for ECN-C-94-009 11 Economic costs of electricity production in Poland combined heat production and for pumping in pump-storage power sta tions. KS = KtC Kti K,» K,n KchP Khf Klip-Kchp-KllP gggggggg+ + + + + + c c KJ - system production cost, K^P - costs of electricity used for heat production in CHP plants, Kj? - costs of electricity used for pumping in pump-storage stations. The latter two are subtracted because the costs of electricity for heat pro duction are allocated to the heat and the costs of electricity used for pum ping are already accounted for in the stations that produce the electricity used for pumping. Other symbols are explained in table 3.1. 4. ELECTRICITY PRODUCTION COSTS IN OECD COUNTRIES As mentioned in the introduction, the assessment of electricity production costs is needed for two reasons: 1) to be able to design a system with mini mum costs; and 2) to calculate management and operation costs of a sys tem. For the design or extension of a new system expected cash flow ac counting is often applied, while the second case determines how costs need to be accounted for and how they can be used for operational decisions. 4.1 Costs for the design and extension of a power system For the cash-flow method annual expenditures and revenues are estimated and discounted. This is illustrated by means of the following example. Year 0 1 2 3 4 5 6 30 Construction [US $1 100 200 200 600 400 800 0 0 O & M [US $] 50 50 Fuel [US $| 270 270 Production [MWhj 6 6 Discounting means dividing benefits and costs each year by (1 + i)( in which t represents the year and / the discounting factor. This results in the following cost formula: " CFt y HP, io (1 + i)1 LPC - Levelized Production Costs CFt • Cash Flow in year t EP, - Electricity production in year t n - lifetime including construction time For the example above this results in costs of 0.082 $/kWh. Fuel costs The prices and price structures of fuels differ per fuel. In the Netherlands the fuels which are mainly used for electricity production are natural gas, coal and uranium. ECN-C-94-009 13 Economic costs of electricity production in Poland The price of natural gas depends on oil prices, the price of coal depends on world market prices and the price of uranium determines only partly the fuel costs for nuclear stations. The major costs arise from the fuel cycle. Price structures of fuels may occasionally change during the lifetime of the plant. It is however difficult to account for these changes at the beginning of the lifetime. Inflation and escalation Parameters strongly influencing the outcomes of the cost calculation are inflation and escalation. A clear distinction has to be made between these parameters. Inflation refers to overall price increases through the devalu ation of money. Escalation refers to the price changes that exceed inflation ary effects. Expected escalation can therefore not be neglected. Consequently applying inflationary effects implies that not only real re spectively current interest rates are used, but also that costs of operation and maintenance as well as fuel costs are adjusted for inflation. No dif ferences in conclusions occur unless tax is paid and the fiscal annual ac count does not allow adjustments for inflation. The same conclusions can be drawn for the opposites of inflation and escalation, namely deflation and falling real prices. Because no real differences occur taking inflation into account, in the re maining of this report all calculations will be made without inflation. 4.2 Cost allocation for an existing system For cost accounting, for the determination of tariffs and for operational decisions a useful and correct assessment of the costs of electricity is ne cessary. The whole process from total expenditures of a power system to economic costs of electricity production per year and per category is shown schematically in figure 4.1. Three steps can be broadly identified. The first step is to divide total costs into cost categories. These categories represent various important cost components of the products. For electri city the most important categories are assets, operation & maintenance and fuels. The second step is to decide whether expenditures can directly be seen as costs or whether they need to be activated. Activating means that goods are used for more than one year so the expenditures have to be divided over several years. An example is the investment in the power plant. The investment is needed before the plant comes into operation, while it usually produces electricity for a period of about 25 years. Costs per year can be determined by means of depreciation. Parameters for depreciation are the lifetime of the plant and the interest rate. The third step is the allocation of costs to fixed and variable costs. Fixed costs refer to those costs that are relatively independent of the actual amount of electricity produced. The most important fixed cost elements are costs of capital and most of the costs of operation and maintenance. The 14 ECN.C9ii.nOQ Electricity production costs in OECD countries variable costs of power production (mostly fuel costs and some O&M costs) depend more or less linearly on the actual amount of electricity pro duced. This separation is useful for determining tariffs and decisions concerning dispatch oider. For the comparison of the production costs of different generating technologies the distinction between fixed and variable costs is also important. For dispatch order decisions (short term planning), only variable costs are taken into account. Total expenditures Assets Operation and maintenance Fuels Activate ?? / \ Yes No \ Life t«n« Interest rat* Depreciation mettwd Fixed costs Variable costs Figure 4.1 Economic costs of electricity production in the annual account Explanation Assets Expenditures on activated assets are fixed costs. Expenditures which are treated as costs in the year they are made can be both fixed and variable. O&M Costs of operation and maintenance are mostly fixed such as costs of personnel. However sjme maintenance is usually variable and also environmental facilities may include variable components (filters or C02 storage). Fuels The costs of fuels are usually variable. However it is possible that contracts are established for a fixed price for a certain period, whether the fuel is taken or not. Assets The capital costs of activated assets consist of depreciation and interest. Interest The interest or discount rate / to be used in cost calculations usually con sists of a number of elements. The most commonly used elements for pri vate companies are the interest charge to be paid on debt fa), the interest Economic costs of electricity production in Poland 1 charge to ts paid on preferred stock (q2), the required return on equity (qj) and eventually an adaptation for taxes. + . _ P-f)-qrQi q2-Q2+q3'Q3 Q,+Q2+Q3 Q, - amount of debt Q2 - amount of preferred stock Q3 = amount of equity f - tax percentage State-owned utilities often use a rate of discount suggested or imposed by the economic planning authorities which should reflect the cost of capital in the national economy. Depreciation Spreading the investment over the lifetime of a power station is termed depreciation. There are different types of depreciation. They can be de scribed as follows. a. Straight-line Straight-line depreciation means that the amount of depreciation is equal each year: D, « depreciation amount at the end of year t I «investment S - salvage value at the end of the lifetime L - lifetime b. Sum of the year's digits This method provides a larger depreciation charge in the early years of plant life. The annual depreciation charge is the ratio of the digit, represen ting the remaining years of plant life plus one, to the sum of the digits for the entire plant life, multiplied by the investment minus the salvage value. D, • 2 1 These are stocks with specific facilities for the owners {e.g. specific rights for profit sharing end influence on the manangement of a company). 16 ECM-C-94-009 Electricity production costs in OECD countries c. Sinking fund depreciation In this method, a constant annual charge for depreciation plus return on not yet depreciated investment is set at a value such that the net plant in vestment will be fully depreciated at the end of plant life. Dt=^.(I-S) (l+i)L-l 4.3 Economic parameters used in different countries The calculation methods used by the OECD countries do not differ very much. They are all very similar to the method described above. This method is elaborated for the Netherlands in the next chapter. There are however some differences between the economic parameters used for cal culation. The table below contains figures concerning parameters used for coal and nuclear plants in several OECD countries. Parameters for natural gas plants are usually similar to those for coal. Table 4.1 Financial parameters used in several OECD countries Country Construction time Load factor Lifetime1 Discount rate Nuclear Coal Nuclear Coal Nuclear Coal [years] [years] [%1 [%] [years] [years] [%] Denmark 6 63 30/35 5 France 6 4 74 80 25/30-40 25/30 8 Germany 6 4 80 80 20/- 20/- 4/5 Netherlands 7 6 80 75 20/30 15/25 4/5 United Kingdom 6.5 5 75 75 40/40 45/45 8 United States 7 5 ? ? 30/40 30/40 5 1 Amortization lifetime/technical lifetime. ECN-C-94-009 17 ciconomic costs or electricity production in Poland Levelized price [ct/kWh] 40 35 - 30 25 20 15 - 10 _L 2000 4000 6000 8000 Operating hours Natural gas Coal Nuclear Requested power [GVyJ 12 2000 4000 6000 8000 Operating hours Figure 5.1 Deduction of the need for certain types of production capacity 18 ECN-C-94-009 5. COST ASSESSMENT FOR PLANNING PURPOSES Cost calculation of electricity production for planning purposes in the Netherlands is performed oy Sep (Cooperating Electricity Production Companies). These cost calculations consist of several steps, which are graphically illustrated in figure 5.1 on the left page. Firstly for each possible option of thermal electricity production average costs are assessed as a function of the load factor. This means that for each year of the lifetime of the plant capitalized cash flows are estimated per type of production capacity (in base year guilders) dependent on the load factor, and the output in kWh is estimated in present terms. Costs divided by output results in levelized costs. Next, the load duration curve for the total system is determined. The numerical data for figure 5.1 are given in the appendix. Based on the prices found in the first step several different types of \. wer station are suited for certain shares of the load duration curve (in figure 5.1: A = natural gas, B =• coal, C = nuclear). At this stage preliminary con clusions can be drawn, on which types of new power production stations should be installed. The third step is a more detailed calculation. It takes into account the whole production system. The cash flows per year are estimated by means of electricity production simulation models. The output of these models shows the actual amount of fuel needed for the stations and the actual production per year. These models take into account the hourly load pat tern, the pattern of CHP production facilities, the supply pattern of wind power and hydro power. This step results in levelized electricity costs for the whole system. In the Netherlands these costs are calculated in current values, in order to describe practice as good as possible. However, calculations in real or cur rent values do not influence the outcomes of the comparisons if the ap propriate discounting values are used. After these first runs sensitivity analyses are performed to see whether the choice would be different if some parameters are changed. These para meters include fuel prices, interest rate, O&M costs etc. Examples of these sensitivity analysis are shown in figures A, 1-4. One must however realize that costs are not the only factor influencing planning purposes. Economic costs of electricity production in Poland 20 ECN.C--94-0O3 6. POLISH ELECTRICITY PRODUCTION COSTS FORECASTS FOR 1995 AND 2000 6.1 Future system development in Poland The key element of the economic reforms in Poland is the liberalization of the markets and the introduction of market prices. This will significantly affect the demand for electricity. Undoubtedly, rationalization and higher electricity prices will lead to a gradual reduction of electricity consumption. On the other hand the restructuring of industry, mechanization and electrifi cation of agriculture and the higher activity levels of the private sector, will lead to an increase of electricity consumption. Therefore, two main scen arios fcr the development of the public electricity supply up to 2010 are examined. The most important results of these scenarios are shown in table 2.3. Table 6.1 Variants of electricity and CHP development 1991-2010 Specffication Units of measure 1991 1995 2000 2010 Low High Low High Low High 1. Installed capacity GW 32.1 33.7 34.4 36.2 38.7 45.3 48.1 of this: hard coal 17.9 19.2 19.9 20.3 20.3 26.0 27.8 lignite 9.1 9.1 9.1 9.0 10.5 10.4 10.4 gas 0.4 1.4 1.6 1.4 hydro 2.0 2.1 2.1 2.9 2.9 3.0 4.2 autoproducers 3.1 3.3 3.3 3.6 3.6 4.3 4.3 2. Peak demand GW 22.7 24.4 25.8 26.5 29.1 32.4 37.5 3. Gross electricity production1 TWh 134.7 135 154 158 176 198 229 of this: public power plants 126.8 127 146 150 168 190 221 in that: hard coal 70.1 76 91 92 101 118 129 lignite 52.7 48 51 53 60 64 66 4. Gross electricity production per capita kWh/c 3516 3497 3969 4041 4456 4938 5585 5. Electricity import TWh 6.7 6. Electricity export TWh 9.3 3.3 3.3 1.9 1.9 - 7. Available thermal power of CHP GWt 27.3 30.1 30.1 32.8 32.8 35.5 35.5 8. Heat production PJ 215.3 270 270 300 300 320 320 1 The production per type of power station in 1995 and 2000 has also been simulated by a Dutch model. The results of these simulations can be found in appendix C. Source: |7J 6.2 Assumptions The development program of electricity production (low variant), and in particular forecast of electricity demand and related peak of load, are the base for projecting the cost of electricity production. ECN-C-94-009 21 Economic costs of electricity production in Poland The cost projection is expressed in constant 1991 prices and the concept of 'economic costs' (economically justified) is used, in particular for • estimation of fuel costs according to international market prices, taking into account the price escalation, (present coal prices in Poland do not reflect the real costs of production, because they are subsidized); - electricity costs related to pumping in pump-storage power stations; - depreciation straight line allowances based on fixed assets value, which should be actualized (present book-keeping values are circa 6 times lower than the corresponding OECD values). The adoption of 'economic costs' makes the cost of electricity production in Polish power stations more comparable to those in OECD countries. The cost forecasts are elaborated for the years 1995 and 2000: - power station groups (types) listed in table 3.1, - system costs (leveHzed) of electricity production. The forecasts are based on the following assumptions: 1. Fuel costs (international market prices) Fuel prices Transport Total fuel Hard coal ( 2. An escalation of fuel price of 1% per year for each type of fuel. 3. From 1997, the costs for environmental protection per kWh will be about two times higher than in 1992 (decision of the Ministry of Environmental protection). 4. The present book-keeping value of fixed assets are a few times lower than the new fixed assets, which will be actualized in 1996 (about 2.5 times of present value). Therefore depreciation allowances for the year 2000 are based on actualized fixed assets. The following depreciation rates are taken into account: - thermal power stations and CHP - 3.8% (i.e. lifetime of 26 years), - hydro-power plants - 2.5% (i.e. lifetime of 40 years). 5. The Repair and Maintenance costs were calculated taking into account an increase of this costs because of aging of equipment (5% per year) and an increase of capacities. 6. It was assumed that the other fixed costs will grow proportionally to the capacity. Polish electricity production costs forecasts 1995 and 2000 7. It was assumed that for the Polish situation the average real interest rate is 10% annually. In the past the energy investments were financed from the budget of the government. The power sector was not directly charged, but some pay ments were introduced in some periods. They were called obligatory ac cumulation, dividend etc. At present, the new investments will be in prin ciple financed from two sources: - depreciation allowances, - credits from World Bank and Commercial Banks. The power stations will be grouped in holding companies. It is also as sumed that the missing funds will be provided by bank credits to be refun ded in 10 years. 6.3 Forecasts of electricity production costs The forecast of electricity production costs for power station types is cal culated according to the scheme presented in table 3.2. The costs elements are computed taking into account their components. E.g. fuel costs are products of: - prognosed electricity production, - fuel consumption per unit, - fuel price per kg (or t). Other costs elements are calculated respecting their specific features and affecting factors. For each power stations group, the per unit production costs are obtained as quotients of the sum of fixed and variable costs di vided by corresponding production output in the year in question. The cor responding formulas for power stations are shown in table 3.3. The for mulas for fixed costs per MW installed are shown in table 3.4. The calculated per unit economic costs of electricity production in US cents/kWh are given in table 6.2. ECN-C--94-009 23 Economic costs of electricity production in Poland Table 6.2 unit costs of production by types of power stations in UScents/kWh Specification Book-keeping costs Economic costs 1991 1995 2000 1. Hard coal 2.0 3.2 35 3.9 - variable \2 2.4 23 2.8 - fixed 0.8 0.8 1.0 1.1 in this: interest - - 0.1 0.1 2. Lignite 1.4 2.0 2.1 2.6 - variable 1.0 1.6 1.7 IS - fixed 0.4 0.4 0.4 0.7 in this: interest - - 0.0 02 3. CHP (combined) 13 2.1 2.4 3.0 - variable OS 1.5 1.5 1.6 - fixed 0.6 0.6 0.9 1.4 in this: interest 0.0 0.0 02 0.7 4. Gas - - - 13.6 - variable - - - 4.6 - fixed - - - 9.01 in this: interest - - - 5.7 5. Total thermal ps. 1.7 2.6 2.8 33 • variable 1.1 2.0 2.1 23 - fixed 0.6 0.6 0.7 1.0 in this: interest 0.0 0.0 0.1 02 6. Pump-storage p.s. 2.4 3.7 43 63 - variable 1.6 2.9 3.0 32 - fixed 0.8 0.8 13 33 in this: interest - - 03 2.5 7. Run-of-river p.s. 1.7 1.7 1.7 1.8 - variable - - - - - fixed 1.7 1.7 1.7 1.8 in this: interest - - - - 1 The relatively high fined costs are partly caused by lower utilization factor of natural gas power plants. For more detailed infonnation concerning the calculations one can contact the institutes. The expected escalation of fuel prices is the main reason for the increase of variable costs in all types of power stations. The inaease of the fixed costs is mainly a result of the high interest rate of investment credits. Polish electricity production costs forecasts 1995 and 2000 Unit costs [et/kWh] u 12 10 1991 1995 2000 Hard coal | Lignite • CHP • Natural gas 0 Pump-storage [3 Run-of-rivor In thermal power stations a significant diversification of per unit costs can be observed. Lignite power plants have the lowest costs, some 30% lower than the hard coal power plants. This is caused by two key factors: - lower cost of lignite, - much longer utilization time of lignite fired plants (h/y). The cost of electricity produced in CHP plants are by some 30% lower, than the costs of electricity generated in condenser type power stations, hard coal fired. In 2000 this difference will be reduced due to a large investment program in CHP plants. The electricity production costs in CHP plants are relatively low as the benefits of the combined heat and power production are attributed to elec tricity following present standards. The present method will be probably modified, and then the electricity production cost will become higher, and heat costs lower. The per unit costs of gas turbine peak power stations, which are expected to be introduced at 2000, will be 3.5 times higher, than the costs of con ventional thermal power plants, hard coal fired. It is the result of about two times higher variable costs and very high fixed costs due to investment credit costs. The lowest per unit costs are in run-of-river power stations. They are about two times less than in conventional power stations, hard coal fired.The per unit costs of pump-storage power stations are close to the conventional thermal ones. In 2000 they will be, however, much higher due to high inter est rates for credit for the pump-storage plant. ECN-C--94-009 25 Economic costs of electricity production in Poland 6.4 Forecasts for the costs of the power system The total costs of the electricity supplied to the national power system is calculated according to the formula presented in chapter 3.4. The result of calculation of the system production cost is given in table 6.3 Table 6.3 System production costs Specification unit of Book keeping Economic costs measure costs 1991 1991 1995 2000 1. Costs of generation Mil. $ 2019 3093 3378 4733 2. Electricity consumed for heat production Mil. $ 36 56 67 84 3. Electricity consumed for water pumping Mil. $ 30 56 58 102 4. System costs - total Mil. $ 1953 2981 3253 4547 5. Supply to the grid TWh 113.1 113.1 113.5 133.0 6. unit cost c/kWh 1.7 2.6 2.9 3.4 Comparing total production costs in Poland to the costs in the Netherlands shows that even economic costs in Poland are reasonably lower. The main reason is that plants in Poland are relatively old compared to the Netherlands and have therefore lower fixed costs. Despite the increased load factor of the whole system in 2000 (at this time the surplus capacity has almost disappeared) costs in 2000 are higher than in 1995 because of revaluation of fixed assets in 19962. Paragraph 6.2, item 4. 26 ECN-C--94009 7. CONCLUSIONS The following conclusions can be drawn from the results of the study. 1. The way economic costs are calculated in Poland is more or less the same as the methods used in OECD countries, but the values of para meters are sometimes different. However amongst OECD countries also differences exist in parameters used. 2. The book keeping costs (historical costs) applied by power stations are not a good basis for taking right economic decisions. These costs do not reflect real costs because: - low coal costs, much lower than the real production costs and lower than the world prices; - low fixed assets value, resulting in unrealistic low depreciation allow ances. Revaluation of the fixed assets to the OECD level would need about six times increase of the present values. In order to achieve that the cost figures are comparable with figures used by OECD countries it is recommended that the Polish power sta tions apply the 'economic' cost method. This method was examined in this study. 3. The study shows, that the real 'economic' costs of electricity production are approximately two times higher than the costs assessed by means of the traditional book-keeping data. 4. The per unit 'economic' costs of electricity production differ significantly for various types of power stations. In thermal power stations the costs are lowest in lignite fired ones and in CHP plants. The electricity costs in hard coal fired condenser type stations are by 30% higher than in the lignite fired ones and CHP plants. The production costs in run-of-river hydro-power stations are the lowest. However, the share in power production in Poland of these stations is negligible. 5. The investment credit cost will become the most important factor in the near future for the electricity production in contrast with the past when the investment funds were covered by the government budget and in practice the electricity costs were not charged by the credit and interest repayment costs. However, some attempts were made to take into ac count these cost. They were called 'obligatory accumulation' to be paid back to budget, thereafter replaced by 'dividend' up to 40%. Depending on the financial situation of the power company the Ministry of Finance resigned of these payments or lowered the taxes. In the future holding companies for electricity will be able to raise funds from depreciation allowances, which will enable them to cover some 40-50% of the new production investments. The main source for financing new investments are the bank credits. Therefore the new power stations will be charged with high credit costs. For example, by the year 2000, the per unit cost of electricity gener ated in gas turbine peak station will amount approximately 14 c/kWh taking into account the interest repayment rates, but without these rates it would be only 8 c/kWh. ECN-C--94-009 27 Economic costs of electricity production in Poland 6. The study confirms the necessity of studies of electricity costs as sessment in the Polish power sector, taking into account the quickly changing situation with respect to: - electrical energy and load demand, - energy and fuel pricing, - possibilities to revaluate fixed assets and depreciation allowances, - costs of environment protection, - availability of funds and credits for new investments (from World Bank and commercial banks). 7. At the moment surplus capacity in Poland exists because of the drop in electricity demand due to the economic reforms. ECN model cal culations for electricity production simulation indicate that only towards the year 2000 this surplus capacity will slowly disappear. This surplus capacity implies higher costs for Polish electricity. Fully implementing economic costs within a few years would mean the rising of prices be cause of revaluation of assets, payment of interest and surplus capacity costs. This development may be socially unacceptable. 8. Improving fuel logistics to power stations can result in lower costs for produced electricity, because in that case the cheaper stations (i.e. lig nite) can reach higher load factors. REFERENCES [11 Fuel and energy statistics 1990-1991. Ministry of Industry and Trade, Central Statistical Office, Warsaw, October 1992. [2J Statistics of Electricity 1970-1991. Ministry of Industry and Trade, Energy Information Centre. [3J Polish Power Industry 1992. Statistical Pamphlet, Ministry of Industry and Trade, Energy Information Centre, Warsaw, April 1993. [41 K. Adamczyk, J. Cofala, S. Okrasa: Key Elements of Energy Policy of the Republic of Poland fcr the Next Twenty Years. 15 Congress of WEC, Madrid, September 1992. [5] Assumptions of Polish Energy Policy to the Year 2010. Synthetic Version. Ministry of industry and Trade, Polish Academy of Science, Department of Energy Problems, Warsaw, 1992. [6J J. Soiinski et al.: Forecast of Economic and Financial Situation of Electricity up to 2000. lEn. Warsaw, October 1992. [7] Different reports of IEn., System Development department, Warsaw. [81 Projected Costs of Generating Electricity. OECD Nuclear Energy Agency & International Energy Agency, Paris, 1989. \7\ Electricity Supply in the OECD. International Energy Agency, Paris, 1992. [10] 1993 European Electric utility Directory. Pennwell Directories, Tulsa, 1993. [11] AJ.M. van Wijk, E.A. Alsema, R.A. van den Wijngaart: The Simulation Model SEPÜ. Reference Guide and Program Description, Utrecht, 1986 (Dutch). [12] R.M. Klein Nagelvoort: Costs and Expenses. Culemborg, 1986 (Dutch). [13] Personal comments of E. Pelgrum, Sep. [14] Expansion Planning for Electrical Generating Systems. International Atomic Energy Agency, Vienna, 1984. ECN-G-94-009 29 Economic costs of electricity production in Poland levelized costs Jct/VWh] Levelized costs |ct/kWh) 40 as > rn j. 2000 4000 6 000 0 2000 4000 60X BOOO z Operating hours Operating hours D Natural git Coil Natural gas Coal Nuclear >< Figure A.1 Leueiued costs, higher fuel price escalation Figure A.3 Levelized costs, lower interest rate > m rn 2 < Levelized costs |cVkWh) Levelized costs |ct/kWh] en rn 40 35 qc 35 - 30 3 N 30 _l_ J_ -1_ CO 0 2000 4 000 6000 aooo 0 2000 4000 6000 aooo Operating hours Operating hours Natural gas Coal Nuclear Natural gat Coal Nuclear Figure A.2 Leueiued costs, hwer interest rate Figure A.4 Leueiued costs, longer life time Economic costs of electricity production in Poland Data used for figure 5.1 and figure A. 1-4 Base case Natural gas Coal Nuclear Investment [//kWJ 1400 2100 3500 Lifetime [year] 25 25 25 O&M [//kW^'year] 40 80 120 Efficiency [%] 52 42 34 Fuel costs L//GJ1 8 6 2 Escalation [%] 2 1 0 Interest rate [real] 5% Case 1: Stronger fuel price escalation This case represents an increase of the natural gas price of 9% per year, coal 3% and uranium 1%. In this case coal is preferable over natural gas for annual operating hours above 2000 hours (base-case almost 3000) and nuclear is preferable over coal at 5000 hours (base case around 7000). Case 2: Lower interest rate If an interest rate of 4% is used instead of 5% the costs of capital diminish, so the capital intensive types of power production become more attractive. Nuclear is then less costly than coal at around 6500 operating hours. Case 3: No fuel price escalation This case assumes no increase of fuel prices at all. In this case natural gas is cheaper than coal and nuclear power for lower operating hours. For high operating hours differences are very small between the three options. Case 4: Longer lifetime If a longer lifetime of the production facilities is assumed (30 years instead of 25) then capital intensive power stations become more attractive. Levelized costs sensitivity analysis Electricity production costs by type of power production [et/kWh] Numerical output Operating hours Natural gas Coal Nuclear Base case 1000 1934 22.88 34.40 2000 12.84 13.45 18.20 3000 10.67 1031 12.80 4000 9.58 8.74 10.10 5000 8.93 7.80 8.48 6000 8.50 7.17 7.40 7000 8.19 6.72 6.63 8000 7.96 638 6.05 Lower interest rate 1000 18.64 21.74 32.54 2000 12.55 12.91 17.27 3000 10.52 9.96 12.19 4000 9.51 8.49 9.64 5000 8.90 7.61 8.11 6000 8.49 7.02 7.10 7000 8.20 6.60 637 8000 7.99 6.28 5.83 Longer lifetime 1000 19.01 21.96 32.82 2000 12.85 13.04 17.41 3000 10.80 10.06 12.28 4000 9.78 8.57 9.71 5000 9.16 7.68 8.17 6000 8.75 7.09 7.14 7000 8.46 6.66 6.41 8000 8.24 6.34 5.86 Stonger fuel price escalation 1000 26.56 23.89 34.63 2000 20.05 14.47 18.42 3000 17.89 1133 13.02 4000 16.80 9.76 1032 5000 16.15 8.81 8.70 6000 15.72 8.18 7.62 7000 15.41 7.74 6.85 8000 15.17 7.40 6.27 Mo fuel price escalation 1000 17.55 22.47 34.40 2000 11.05 13.05 18.20 3000 8.88 9.90 12.80 4000 7.80 8.33 10.10 5000 7.15 7.39 8.48 6000 6.71 6.76 7.40 7000 6.40 6.31 6.63 8000 6.17 5.98 6.05 Economic costs of etectricity production in Poland 34 ECN-C-M.OrtO APPENDIX B. COSTS OF POWER AND HEAT IN CHP PLANTS Poland The present method used in poland is under discussion and wilt be changed. This method of cost separation between electricity and heat is based on following principles. Fuel costs are divided taking into account the fuels energy consumed to produce electricity and heat. The amount of chemical energy used for heat is calculated from the heat output from CHP plant divided by boilers and pipelines efficiency factor. It is called the 'heat share'. The difference be tween the total chemical energy of fuels consumed minus the heat share is taken as the share for electricity production. Other variable costs are divided between heat and electricity as follows: a. fuels purchasing costs proportionally to the amount of fuels consumed for heat and electricity respectively, b. chemicals and technological water costs - proportionally to the chemical energy consumed, c. environment protection costs - as in a). Fixed costs of production are divided between heat and electricity as fol lows: - common costs of boiler house and other production sections - propor tionally to capacity (MWe and MWt), • costs of sections working only for electricity charge electricity production, - costs of sections working only for heat production charge heat. Netherlands Assessing the costs of combined heat and power production (CHP) leaves room for arbitrary allocation of the costs. Because electricity and heat are generated simultaneously no clear distinction in cost structure can be made. Most often one of the two products (heat/power) is priced according to the costs of substitutes, for example heat from boilers, electricity for average system costs. In the Netherlands the cost assessment of this type of power production also depends on the nature of the ownership, Recently CHP is most often installed under a joint venture between an industrialistic partner and a dis tribution company. In this case the heat is supplied to the private company based on the costs of separate heat production with boilers (minus a 10% discount) and the electricity is supplied to the distribution company for the average production costs of the Dutch grid. Eventual profits of the joint-venture are shared between the distribution company and the in dustrialistic partner. Another recent development is the 'heat plan'. This plan is developed by Sep (cooperating production companies) and according to their electricity plan 1993-2002 comprises almost 2500 MWe CHP production for both ECN-C--94-009 35 Economic costs of electricity production in Poland district-heating as well as industrial heat (STAG). Recent developments in cost calculation for these CHP plants show that agreements have been made that the electricity producer bears the risk of fuel price escalation and that the heat distributor is responsible for the number of connections. In concrete this implies that when the price of natural gas escalates and from an economical point of view it would be attractive to use coal power plants for production instead of the CHP plants, this is not possible because heat has to be delivered. This means a higher price for electricity. On the other hand, when the number of connections does not reach the number that was expected the losses are taken by the heat distributor. APPENDIX C. SIMULATION OF ELECTRICITY PRODUCING UNITS The results in chapter 6 concerning electricity production per type of power station have been determined by the models used by lEn. In order to com pare the model used by lEn and the model used by ECN for electricity production the Dutch model has also been used to simulate Polish electri city production. The ECM-model has been developed by the University of Utrecht. This model is called SEPU and determines the optimal electricity production over a year with a given supply system and demand. It is written in turbo-pascal 4.0 under MS-DOS 4.0. On a Tulip dt-486 it takes about 30 minutes to simulate electricity production for one year. C.l The SEPÜ model Input The model needs 4 input-files, to be recognized by différent extensions. Two output files are produced. This is shown graphically in figure C.l. Each of the files is described briefly. Figure C.l Structure of the simulation model 1 File *.inu This file contains scenario dependent parameters, like year of simulation, total demand and some special parameters concerning the structure of the output. Economic costs of electricity production in Poland 2 Ftle\een This file contains a list of all electricity producing units, as wedfor publi c as for private power plants. The units are grouped in types of power stations like brown coal, hard coal. CHP, hydro, import, etc. For each unit this file contains information on nominal capacity, years of starting up and closing down, type, planned and unplanned maintenance per year, efficiency, emissions and start-up times. 3 Fik\bef This file contains the load-pattern for the total system. For each hour of the year total demand is given. Scenario's with different total demands are scaled up/down linearly. 4 File *.inz The file *.Inz contains a list of the dispatch order for the different types of power stations. This dispatch order is usually based on the variable costs of each type and can also be based on production patterns of load-following (like CHP) or supply-following (like wind and hydro) types of power. Running of SEPÜ The actual simulation is performed in two steps. Firstly a revision scheme is created. This scheme is based on the expected demand (expected de mand is lower in the summer, so more room for revision) and also on load characteristics (CHP preferably in the summer, because there is little heat demand in summer). Based on the revision scheme the simulation can start. During simulation, at the beginning of each week, the stations that are not available because of revision are erased of the list of available units for that week. Secondly each unit is derated based on the percentage of unplanned maintenance. Based on expected demand, each day a planning scheme is created for the next 34 hours. This determines whether stations can be shut down temporarily or whether they are expected to generate. It is also determined for storage systems, at which moments they are ex pected to pump and to generate electricity. Output The output of SEPÜ consists of two files. 1 File *.rev The *.Rev file contains the results of the revision planning. For each unit the weeks of planned maintenance are given. It also shows the total amount room for revision in each week. 2 File *.sim The *.Sim file shows the results of the simulation. For each type of power station, as well as for each station separately, total production, load factor, fuel use and emissions are assessed. Furthermore the number of cold and hot starts is given. 38 simulation electricity producing units C.2 Differences between Poland and the Netherlands Based on the structure of SEPCI the differences between Polish and Dutch electricity production system are discussed below. Electricity demand The most important exogenous parameter for electricity is total demand. For the year 2000 expectations about final electricity demand in the Netherlands vary between 90 and 100 TWh. For Poland the expected gross production varies between 158 and 176 TWh, including 1.9 TWh of ex ports. Power system The fuel package of the Polish system differs significantly from the Dutch system. In Poland over 90% of electricity is generated from coal (hard coal and lignite). The remaining central production is based on hydro and natu ral gas plants, the latter one being very low in 2000 (< 1% of total produc tion). Auto production (coal used as fuel) provides for about 7% of total electricity production. In the Netherlands coal power stations (only hard coal) are solely used for base-load.In the Netherlands the expected share of coal in total electricity production in 2000 is some 25% (see figure C.2). The remaining comes from imports, nuclear, natural gas, public CHP, autoproducers (natural gas used as fuel) and renewables (mainly wind). 2000 (97,5 GWh) • Import [I] Nuclear | Coal [J Natural gas B Public CHP Ê3 Auto producers Q Renewables Figure C.2 Fuel package Dutch electricity production in 2000 An other important distinction between Poland and the Netherlands, is that Poland has pumped-storage hydro plants at its disposal. These storage systems normally pump during the night and generate electricity during peak hours, usually in the afternoon. 39 Economic costs of electricity production in Poland The average efficiency of Dutch power systems is higher than the efficiency of Polish stations. This is mainly caused by the fact the Polish stations are older and because of the fuels used (in Poland less natural gas than in the Netherlands). Also emissions are higher because in the Netherlands much effort is given to flue gas desulphurisation and reduction of no„-emissions. No data were available on starting times of units for the Polish system. Therefore dutch data have been used. These last set of data don't influence the outcomes of the simulation very much. Demand pattern Comparison of the expected load pattern in 2000 for Poland and the Netherlands shows some remarkable differences. This is illustrated by fi gures C.3a-d. These figures show the load duration curves (LDC) for the Netherlands and Poland by season and over the whole year. It appears that the curve for Poland per season is more flat than for the Netherlands, al though the peaks are relatively steep. This means that the average dif ference between day and night in the Netherlands is larger than in Poland, but that the load-differences in the daytime are less than in Poland. This difference is probably caused by the Dutch tariff-system, in which it is very important for large consumers to purchase little electricity during national peak demand. LOAD LOAD TIME Figure C.3a Idc 2000, ƒ* season Figure C.3b Idc 2000, 2nd season LOAD LOA0 TIME TIME Figure C3.c Idc 2000, 3rd season Figure C.3d Idc 2000, 4th season The load duration curve over the whole year shows that in Poland the peak is much steeper than in the Netherlands. The maximum/minimum demand ratio in both countries is almost equal. The effect of a larger difference between day and night demand in the Netherlands is compensated by the fact, that the differences per season in Poland are larger. 40 ECN-C-94-009 simulation electricity producing units LOAD 1.4 1.2 1 0.8 0.6 0.4 0,2 0 0 0,2 0.4 0,6 0.8 1 TIME Poland Netherlands Figure C.4 Load duration curve 2000 Dispatch order In accordance with the variety in unit types, the dispatch order in the Netherlands is much more extensive. Partly, this is caused by a lack of data and also because the Dutch model is tuned for the Dutch situation. For example, for autoproducers in the Netherlands ten different demand patterns are used (basic industry, food industry, market gardeners, hospi tals, etc), while autoproduction in Poland is less extensive, while on the other hand in Poland much more variation exists in different types of coal-fired plants. C3 Input used for the Polish system For the simulation electricity demand is based on the low-scenario. For the year 2000 this means total demand of 156 TWh. The complete list of power stations is given in combination with the results in appendix D. The load pattern has been extensively discussed in chapter 2. For the dispatch order the following assumptions were taken. A distinction has been made between the following categories: - Autoproducers The electricity production by autoproducers depends on the pattern of the steam demand. Based on a Dutch production pattern for auto producers and total production according to Polish statistics (1990) a production pattern was constructed, resulting in a load factor of around 3200 hours/year. Autoproducing capacity is expected to grow from 3,1 GW in 1990 to 3,6 GW in 2000. - Hydro The production of hydro plants depends on the availability of water. In accordance with the autoproducers, a pattern for Polish hydro plant pro duction has been constructed based on a Dutch pattern and Polish total 41 Economic costs of electricity production in Poland production in 1990. The expected growth towards 2000 is around 850 MW. - Combined heat and power the production of CHP plants depends on the steam demand. For the first calculations the dutch pattern for electricity production in combination with steam production for households has been used. This results in load factor of 3300 hours/year. CHP capacity is expected to grow 1,65 GW in the period from 1992-2000. - Lignite Lignite power plants have the lowest variable costs of the thermal power stations. That's why they are used for base load. After pattern following types of power stations they are put up first in the dispatch list. - Hard coal, efficiency > 36,5% In the SEPU-model a certain share of the power plants must be deter mined for peak demand. For this reason the hard coal plants have been split up in two categories. The stations with an efficiency above 36,5% are supposed to operate for base load and middle load. - Hard coal, efficiency < 36,5% The hard coal power stations with an efficiency below 36,5% are sup posed to supply peak demand. This means that these units must have relatively short starting times less than 1 hour). - Pumped storage the operation strategy for the pumped storage power plants depends on the variable costs of the other units and on the efficiency of the combined pump and turbine system. Based on information received from lEn, the pumping takes place daily during the night and production takes place during afternoon peak demand. In the ECN-model it is not possible to determine the times, when the pumped storage systems are to pump and to generate. In the input, one needs to determine which stations can be used to fill the storage system (stations with low variable costs), and the stations, whose production can be replaced by the storage system (sta tions with high variable costs). This strategy needs to be tuned during the working session at f En. C.4 Results of the simulation As described in chapter 3 some problems were encountered with the ap propriate strategy for the pumped-storage system. Therefore first some simulations have been made without pumped storage. Next some variants have been made to gain insight in the effects of the pumped storage sys tems. First results of these variants show that the load factor of base load (mainly lignite) goes up some 300 hours/year. Results of simulation for 1995 Because of practical reasons the production pattern of the year 2000 has been used for 1995. The total demand is 138 TWh. The results of the simu lation for 1995 are shown in table C.l. 42 ECN.C-94-009 Simulation electricity producing units Table C.l Simulation results for 1995 Type Capacity Production Load factor Fuels NO, SOz Efficiency |MW] [TWh] [hours/year) IPJ1 [mln kg] [mln kg] [%] Autoproducers 3400 10.9 3203 CHP 3677 12.0 3286 67.7 16.1 43.6 64.2 Hydro 683 1.6 2413 Lignite 8938 58.7 6566 613.9 135.1 689.7 34.4 Hard coal 1 6557 36.3 5529 343.4 81.1 261.4 38.1 Hard coal 2 9143 18.4 2018 186.3 56.2 173.1 35.7 Natural gas 0 0 0 0 0 0 0 Total 32398 138 4260 1342 314.6 1167.9 37.1 In 1995 there is still some overcapacity resulting from the drop in demand after the economic reforms. Because no extensive data were available for the autoproducers, figures for efficiency and emissions have been omitted. Results of simulation for 2000 The results of the first simulation for 2000 are shown in table C.2. The new gas power plant does not generate much electricity because of the high variable costs. The overcapacity has almost disappeared in 2000. There fore average load factors per type as well as for the whole system have increased. A Dutch model for reliability analysis indicates that according to dutch standards the system reaches the border of acceptable reliability in 2000. This calculation however did not include the pumped-storage system and the expected exports. Table C.2 Simulation results for 2000 Type Capacity Production Load factor Fuels NOx S02 Efficiency |MW] [TWhl [hours/year] [PJJ (min kg] [mln kg] [%] Autoproducers 3600 11.7 3256 CHP 4727 15.6 3306 90.0 20.4 54.6 62.5 Hydro 1433 3.5 2433 Lignite 8640 57.7 6678 601.0 134.0 678.8 34.6 Hard coal 1 7277 42.1 5780 396.8 93.5 295.8 38.2 Hard coal 2 8997 25.7 2854 262.7 77.7 251.8 35.2 Natural gas 350 0.1 381 1.9 0.2 0.0 45.0 Total 35024 156.4 4466 1493.1 353.9 1281.0 37.7 Analyzing the differences between the simulation of the dutch model and the scenarios given in chapter 6 show that the lignite power plants produce more electricity according to the Dutch model and coal-fired power plants produce less than in the Polish scenarios. It appeared that an important reason for these differences are the shortages of fuel that sometimes occur in lignite power plants. These shortages are usually caused by logistic problems. From a cost point-of-view it would therefor be attractive to solve these logistic problems. ECN-C-94-009 43 LAAS!IUI1 III. I.U9UUI CICVUIUIJT |nUUUV.UUII III rUMIIU Taking into account the possibility of storage of electricity would mean that lignite-fired plants could even reach a higher load factor. Another striking difference is the average load factor for autoproducers. In the Netherlands for industrial customers it is near 6000 hours/year, while in Poland it is between 3000 and 3500 hours. 44 ECN-C--94-009 APPENDIX D. PRODUCTION PER UNIT IN 2000 1 unit Type Capacity Production Load factor Fuels NOx SO: [MW] [GWh] [hours/year] |PJ] (mln kgl [mln k AÜTOPRODÜCERS 3600 11721 3256 HALEMBA1 CHP 200 662 3308 2.7 0.6 1.6 BYDGOS22 CHP 169 565 3343 2.5 1.0 1.6 GDANSK-2 CHP 187 625 3340 2.8 1.0 1.8 KAROUN CHP 155 517 3337 2.5 0.5 1.7 ZIELONA CHP 11 37 3336 0.2 0.0 0.2 PRUSZKOW CHP 6 20 3336 0.1 0.0 0.0 CZECHNICA CHP 132 422 3198 2.2 0.7 1.5 BYDGOSZ3 CHP 33 110 3336 0.6 0.2 0.3 BIALYSTOK CHP 118 394 3336 2.1 1.0 1.7 LODX-1 CHP 524 1747 3334 9.4 1.3 5.6 WROCLAW CHP 267 889 3328 4.8 1.4 4.5 SZCZECIN CHP 48 160 3324 0.9 0.1 0.6 POWISLE CHP 42 140 3322 0.8 0.1 0.3 GDYNIA-2 CHP 133 442 3322 2.5 0.9 1.3 BED2N CHP 55 183 3320 1.1 0.4 1.0 ZERAN CHP 250 829 3316 5.0 2.0 4.1 SIEKJERKJ CHP 622 2055 3305 12.6 1.6 7.4 CHP-1 CHP 600 1975 3291 12.4 2.4 6.1 CHP-2 CHP 525 1724 3284 10.9 2.1 5.3 CHP-3 CHP 525 1723 3283 10.9 2.1 5.3 BYDGOSZ1 CHP 14 46 3283 0.3 0.6 0.1 GARBARY CHP 11 36 3283 0.3 0.6 0.2 BIALA CHP 100 328 3283 2.7 0.8 2.1 SUBTOTAL 4727 15627 3306 90.0 20.4 54.6 HYDR2 HYDRO 375 912 2433 HYDR3 HYDRO 375 912 2433 WISLA HYDRO 160 389 2433 SOUNA HYDRO 136 331 2433 DÜNAJEC HYDRO 58 141 2433 KORONOWO HYDRO 26 63 2433 TRESNA HYDRO 21 51 2433 DEBE HYDRO 20 49 2433 BOBR HYDRO 19 46 2433 ODRA HYDRO 16,7 41 2433 RADUNIA HYDRO 14.1 34 2433 PORABKA HYDRO 12.6 31 2433 NYSAKLODZ HYDRO 9.2 22 2433 BOBR-2 HYDRO 8.8 21 2433 SAN HYDRO 8.3 20 2433 ZCJR HYDRO 8.0 19 2433 SLÜPIA HYDRO 7.8 19 2433 GWDA HYDRO 7.6 18 2433 KWISA HYDRO 6.6 16 2433 WISLA HYDRO 5.8 14 2433 RADEW HYDRO 4.4 11 2433 NYSA-LCIZ HYDRO 4.2 10 2433 SMUKALA HYDRO 4.0 10 2433 GRODEK HYDRO 3.9 9 2433 PIUCA HYDRO 3.4 8 2433 LVNA HYDRO 3.4 8 2433 PASLEKA HYDRO 3.2 8 2433 (continued on page 46) ECN-C--94-009 45 Unit1 Type Capacity Production Load factor Fuels NO, SO, [MWJ [GWh] [hours/year! [PJ] [mln kg] [mln kg] REGA HYDRO 2.8 7 2433 BYSTRZYCA HYDRO 2.1 5 2433 MALAPANEW HYDRO 1.8 4 2433 SKAWTNKA HYDRO 1.6 4 2433 OBRA HYDRO 1.3 3 2433 ODRA HYDRO 1.1 3 2433 WIERZYCA HYDRO 1.1 3 2433 DRAWA HYDRO 1.0 2 2433 LUPAWA HYDRO 0.9 2 2433 DRAWA HYDRO 0.9 2 2433 WTTKA HYDRO 0.8 2 2433 KAMIENNA HYDRO 0.8 2 2433 WIEPRZA HYDRO 0.4 2433 MYSLA HYDRO 0.4 2433 WALSZA HYDRO 0.4 2433 OLCZA HYDRO 0.3 2433 PARSETA HYDRO 0.3 2433 SKOTAWA HYDRO 0.2 0 2433 WADAG HYDRO 0.2 0 2433 BYSTRY HYDRO 0.2 0 2433 OLOWNIK HYDRO 0.2 0 2433 STÜDNICA HYDRO 0.1 0 2433 GRABOWA HYDRO 0.1 0 2433 HYDR1 HYDRO 92 224 2433 SUBTOTAL 1433 3486 2433 BELCH-1 UGNTTE 720 4973 6907 49.7 14.1 63.1 BELCH-2 UGNTTE 720 4970 6903 49.7 14.1 63.1 BELCH-3 LIGNITE 720 4966 6898 49.6 14.0 63.0 BELCH-4 LIGNITE 720 4961 6890 49.6 14.0 63.0 BELCH-5 LIGNITE 720 4955 6882 49.5 14.0 62.9 BELCH-6 LIGNITE 720 4949 6874 49.5 14.0 62.8 PATNOW-1 UGNTTE 600 3926 6544 40.2 5.8 38.9 PATNOW-2 LIGNITE 600 3918 6530 401 5.8 38.9 PATNOW-3 UGNrTE 400 2607 6518 26.7 3.9 25.9 ADAMOW-1 LIGNITE 480 3046 6347 33.7 7.2 11.2 TÜROW-1 LIGNITE 500 3242 6484 36.3 6.2 42.4 TÜROW-2 LIGNITE 500 3234 6468 36.2 6.2 42.3 TUROW-3 UGNrTE 500 3226 6453 36.1 6.2 42.2 TUROW-4 UGNITE 500 3218 6436 36.0 6.2 42.1 KONIN-8 UGNrTE 240 1504 6265 18.2 2.3 16.9 SUBTOTAL 8640 57696 6678 601.0 134.0 678.8 STALOWA3 HARD-COAL 1 345 1953 5662 15.9 4.9 10.6 KRAKOW HARD-COAL 1 460 2829 6149 23.4 11.1 17.4 POMORZAN1 HARD-COAL 1 112 710 6339 6.5 2.3 5.0 GPOLE-1 HARD-COAL 1 360 2189 6080 20.4 4.5 12.5 OPOLE-2 HARD-COAL 1 360 2165 6015 20.1 4.4 12.4 OPOLE-3 HARD-COAL 1 360 2143 5953 19.9 4.4 12.3 OPOLE-4 HARD-COAL 1 360 2122 5895 19.7 4.3 12.1 OPOLE-5 HARD-COAL 1 360 2099 5831 19.5 4.3 12.0 OPOLE-6 HARD-COAL 1 360 2073 5759 19.3 4.2 11.9 POLANIEC1 HARD-COAL 1 600 3892 6487 37.7 5.0 31.6 P0LANIEC2 HARD-COAL 1 500 3231 6463 31.3 4.2 26.3 POLAHIEC3 HARD-COAL 1 500 3199 6399 31.0 4.1 26.0 KOZIEN-5 HARD-COAL 1 600 3452 5753 33.8 9.2 27.1 KOZIEN-1 HARD-COAL 1 500 2830 5661 27.7 7.5 22.2 KOZIEN-2 HARD-COAL I 500 2815 5631 27.6 7.5 22.1 KOZIEN-3 HARD-COAL 1 500 2231 4462 21.9 5.9 17.6 KOZIEN-4 HARD-COAL 1 500 2126 4252 20.9 5.6 16.8 SUBTOTAL 7277 42061 5780 396.8 93.5 295.8 (continued on page 47 46 ECM-C-94.00 Production per unit in 2000 unit1 Type Capacity Production Load factor Fuels MO, SO, [MW] [GWh] [hours/year] [PJ1 [mln kg! [mln kg] KAL1S2 HARD-COAL 2 8 38 4721 0.3 0.1 0.2 DOLMA-1 HARD-COAL 2 200 973 4865 9.6 3.2 8.3 DOLHA-2 HARD-COAL 2 200 951 4754 9.4 3.1 8.1 DOLNA-3 HARD-COAL 2 200 929 4646 9.2 3.0 7.9 DOUSA-4 HARD-COAL 2 200 1031 5156 10.2 3.4 8.8 DOLMA-5 HARD-COAL 2 200 1011 5054 10.0 3.3 8.6 DOLMA-6 HARD-COAL 2 200 993 4965 9.8 3.2 8.4 DOLNA-7 HARD-COAL 2 200 973 4867 9.6 3.2 8.3 DOLNA-8 HARD-COAL 2 200 953 4766 9.4 3.1 8.1 OSTROLEK1 HARD-COAL 2 200 865 4324 8.7 2.9 10.8 OSTROLEK2 HARD-COAL 2 200 846 4230 8.5 2.8 10.6 OSTROLEK3 HARD-COAL 2 200 826 4131 8.3 2.7 10.4 RYBMIK1 HARD-COAL 2 200 827 4137 8.3 2.4 5.8 RYBNIK2 HARD-COAL 2 200 806 4029 8.1 2.3 5.7 RYBMIK3 HARD-COAL 2 200 784 3920 7.9 23 5.5 RYBNIK4 HARD-COAL 2 200 756 3779 7.6 2.2 5.3 RYBNIK5 HARD-COAL 2 200 730 3652 7.4 2.1 5.2 RYBNIK6 HARD-COAL 2 200 703 3514 7.1 2.0 5.0 RYBNIK7 HARD-COAL 2 200 677 3384 6.8 2.0 4.8 RYBMIK8 HARD-COAL 2 200 649 3246 6.5 1.9 4.6 LA2SKA9 HARD-COAL 2 200 622 3112 6.4 i.6 4.7 LAZISKA10 HARD-COAL 2 200 593 2965 6.1 1.6 4.5 LAZISKA11 HARD-COAL 2 200 570 2849 5.8 1.5 4.3 LAZJSKA12 HARD-COAL 2 200 591 2955 6.0 1.5 4.5 LAZBKA1 HARD-COAL 2 120 311 2594 3.2 0.8 2.4 LAZISKA2 HARD-COAL 2 120 331 2759 3.4 0.9 2.5 JAWORZ1 HARD-COAL 2 200 565 2826 5.8 1.6 9.2 JAWORZ2 HARD-COAL 2 190 508 2676 5.3 1.5 8.3 JAWORZ3 HARD-COAL 2 190 480 2529 5.0 1.4 7.8 JAWORZ4 HARD-COAL 2 190 454 2387 4.7 1.3 7.4 JAWORZ5 HARD-COAL 2 190 430 2264 4.4 1.3 7.0 JAWORZ6 HARD-COAL 2 190 406 2136 4.2 1.2 6.6 ELBLAG HARD-COAL 2 62 122 1965 1.3 0.6 0.7 LAGISZA1 HARD-COAL 2 105 196 1870 2.1 0.4 2.3 LAGISZA2 HARD-COAL 2 105 189 1804 2.0 0.4 2.2 LAGISZA3 HARD-COAL 2 105 182 1734 2.0 0.3 2.2 LAGISZA4 HARD-COAL 2 105 175 1670 1.9 0.3 2.1 LAGIS2A5 HARD-COAL 2 105 168 1604 1.8 0.3 2.0 LAGISZA6 HARD-COAL 2 105 163 1552 1.8 0.3 1.9 LAG1SZA7 HARD-COAL 2 105 158 1502 1.7 0.3 1.9 SIERSZA5 HARD-COAL 2 110 170 1549 1.9 0.6 2.4 SIERSZA6 HARD-COAL 2 110 163 1486 1.8 0.6 2.3 SIERSZA1 HARD-COAL 2 105 150 1428 1.7 0.5 2.1 SIERSZA2 HARD-COAL 2 105 144 1372 1.6 0.5 2.0 SIERSZA3 HARD-COAL 2 105 139 1325 1.5 0.5 2.0 SIERSZA4 HARD-COAL 2 105 133 1266 1.5 0.5 1.9 SZOMBIERKI HARD-COAL 2 44 45 1023 0.5 0.2 0.2 GORZOW HARD-COAL 2 73 81 1115 0.9 0.3 0.7 GDANSK-0 HARD-COAL 2 29 30 1026 0.3 0.1 0.1 CHORZOW HARD-COAL 2 100 104 1043 1.2 0.2 0.9 SKAWINA3 HARD-COAL 2 90 90 1004 1.1 0.4 0.9 SKAWINA4 HARD-COAL 2 90 86 955 1.0 0.4 0.9 SKAWINA5 HARD-COAL 2 90 81 903 1.0 0.4 0.9 SKAWINA6 HARD-COAL 2 90 78 865 0.9 0.3 0.8 SKAWIMA1 HARD-COAL 2 45 37 821 0.4 0.2 0.4 SKAWIMA2 HARD-COAL 2 45 37 819 0.4 0.2 0.4 SKAWINA7 HARD-COAL 2 45 36 801 0.4 0.2 0.4 BLACH! HARD-COAL 2 48 38 784 0.5 0.1 0.4 BLACH2 HARD-COAL 2 48 37 765 0.5 0.1 0.4 BLACH3 HARD-COAL 2 48 36 741 0.4 0.1 0.3 BLACH4 HARD-COAL 2 48 35 725 0.4 0.1 0.3 (continued on page 48) ECN-C-94.009 47 .waswasiaw ^.w***h* W* \.IVVU IVliJ ^IWUUVUUII III rUtflllU Unit1 Type Capacity Production Load factor Fueb MO, SO, [WW] (GWhJ [hours/year] [PJ] [min kgl (min k BLACH7 HARD-COAL 2 26 18 706 0.2 0.0 0.2 BLACH8 HARD-COAL 2 26 18 694 0.2 0.0 0.2 ZABRZE HARD-COAL 2 106 73 692 0.9 0.3 0.6 JAWORZ2-1 HARD-COAL 2 50 32 649 0.4 0.1 0.6 JAWORZ2-2 HARD-COAL 2 50 31 627 0.4 0.1 0.6 JAWORZ2-3 HARD-COAL 2 50 31 621 0.4 0.1 0.6 JAWORZ2-4 HARD-COAL 2 50 30 603 0.4 0.1 0.6 JAWORZ2-5 HARD-COAL 2 50 29 587 0.4 0.1 0.6 JAWORZ2-6 HARD-COAL 2 50 29 571 0.4 0.1 0.6 JAWORZ2-7 HARD-COAL 2 50 28 563 0.4 0.1 0.6 MIECH0WI1 HARD-COAL 2 51 28 558 0.4 0.1 0.6 MIECHOWI3 HARD-COAL 2 50 27 536 0.4 0.1 0.5 GDYNIA-1 HARD-COAL 2 20 12 581 0.2 0.1 0.1 SUBTOTAL 8997 25675 2854 262.7 77.7 251.8 NATGAS-1 NATURAL GAS 350 133 381 1.9 0.2 0.0 TOTAL 35024 156400 4466 1493.1 353.9 1281.0 Different units at the same plant have sometimes been joined for the simulation because of problems with computer memory. 48 ECN-C-94-009
Economic Costs of Electricity Production in Poland
