70017 Energy Consultants Sri Lanka: Environmental Issues in the Power Sector Final Report May 2010 Submitted to the World Bank by: Economic Consulting Associates Resource Management Associates Environmental Resources Management Economic Consulting Associates Limited 41 Lonsdale Road, London NW6 6RA, UK tel: +44 20 7604 4546, fax: +44 20 7604 4547 C:\A1 Files\Project\Sri Lanka EIPS\Docs\Report updated\SriLanka EIPS Report v1c.doc 18/5/10 Contents Contents Executive Summary i 1 Introduction 1 1.1 Background 1 1.2 Approach 2 1.3 Attributes 4 2 The Sri Lanka Power Sector 11 2.1 Review of the past two decades 11 2.2 The present vision (business as usual) 12 3 Assumptions 15 3.1 Macroeconomic assumptions 15 3.2 Various assumptions 16 3.3 Fuel prices assumed in the analysis 17 3.4 Carbon accounting 19 3.5 Demand Forecasts 19 4 Environmental regulations and standards 22 4.1 Consequences of emissions 22 4.2 Principles 24 4.3 The current environmental regulatory framework 27 4.4 Air quality standards 28 4.5 Proposed stack emission regulations 29 4.6 Regulation of Puttalam coal-fired power plant 30 4.7 Implications of emission standards for use of FGD 31 4.8 Environmental damage costs 34 5 Technology options 37 5.1 CCGT (autodiesel) 37 Sri Lanka: Environmental Issues in the Power Sector i ECA, RMA and ERM C:\A1 Files\Project\Sri Lanka EIPS\Docs\Report updated\SriLanka EIPS Report v1c.doc 18/5/10 Contents 5.2 CCGT (fuel oil) 39 5.3 Open cycle combustion turbines 40 5.4 Supercritical technology for coal generation 42 5.5 LNG 44 5.6 Petroleum Coke 49 5.7 Indo-Lanka interconnection 52 5.8 Summary of conventional technologies 53 5.9 Pumped-storage plant 56 5.10 Demand-side management 58 5.11 Screening Analysis 60 6 Policy Scenarios 63 6.1 Sector reform 63 6.2 Renewable energy targets 65 7 Cases 70 7.1 Case definitions 70 7.2 Reference case results 72 7.3 LNG power plants 74 7.4 Medium-scale hydropower plants 74 7.5 Pumped storage option 74 7.6 DSM intervention 75 7.7 Non-conventional renewable energy 77 7.8 Other observations 79 8 Multi-attribute assessment 80 8.1 The reference case 80 8.2 Trade-off curves 90 8.3 Conclusions of the multi-attribute analysis 95 9 Implications for Decision Makers 97 Sri Lanka: Environmental Issues in the Power Sector ii ECA, RMA and ERM Contents Annexes 100 A1 Review of the past two decades 100 A1.1 Demand growth, customers and prices 100 A1.2 Electricity tariffs 102 A1.3 Implementation of long-term plans 103 A1.4 Reasons for high generation costs and prices 105 A1.5 The proliferation of small oil-fired power plants 105 A1.6 Comparison of generation costs 106 A1.7 Attempts to develop coal-fired power generation 108 A1.8 Power sector reforms 109 A2 Detailed assumptions and approaches used 111 A2.1 The treatment of interest during construction (IDC) 111 A2.2 Capacity 111 A2.3 LHV and HHV 112 A2.4 IPP capital costs 112 A3 Carbon accounting 114 A3.1 GHG emissions from reservoirs 115 A3.2 Life cycle emissions 117 A4 Load Forecast 121 A4.1 Introduction 121 A4.2 CEB forecasting model and forecasts 121 A4.3 Consultant’s forecast 125 A4.4 Comparison between forecasts 129 A5 Fuel price forecasts 131 A5.1 Oil and petroleum product prices 131 A6 Definitions of cases used in the analysis 142 A6.1 Policy cases 142 Sri Lanka: Environmental Issues in the Power Sector iii ECA, RMA and ERM Contents A6.2 Sensitivities around the reference case 144 A6.3 Additional case combinations 145 A7 Technology options not considered 146 A7.1 LPG 146 A7.2 Nuclear 146 A7.3 Other clean coal options (Fluidized bed combustion, IGCC) 149 A8 Codes used in diagrams 151 A9 Summary of the results of the cases 152 A10 Detailed outputs from the model for the 15 cases 155 A11 Graphs of the results of the cases 201 A11.1 Baseline 201 A11.2 LNG 202 A11.3 Hydro 203 A11.4 NCRE 204 A11.5 Green 205 A11.6 Forced supercritical 206 A11.7 No coal 207 A11.8 Pumped storage 208 A11.9 Demand-side management 209 A11.10 High demand 210 A11.11 High fuel prices 211 A11.12 Real fuel price escalation 212 A11.13 Low discount rate 213 A11.14 NCRE plus real fuel price escalation 214 A11.15 Pumped storage plus DSM 215 A12 Report on the stakeholder workshop 216 A12.1 Workshop agenda 217 Sri Lanka: Environmental Issues in the Power Sector iv ECA, RMA and ERM Contents A12.2 Organisations represented at the workshop 218 A12.3 Summary of comments at the workshop 219 A12.4 Written comments on the Report 220 Tables Table 1 Capacity shares 8 Table 2 Generation expansion plan 2008 - capacity additions 12 Table 3 Additions and retirements in the Long-Term Generation Expansion Plan 13 Table 4 Central Bank GDP Forecast 16 Table 5 EIPS fuel price assumptions 17 Table 6 Derivation of coal prices 18 Table 7 National ambient air quality standards 28 Table 8 Proposed stack emission standards for larger plants 29 Table 9 Puttalam coal-fired plant – ambient air quality standards 30 Table 10 Damage Cost Estimates 35 Table 11 Damage costs 36 Table 12 CEB assumptions, CCGT (gross basis) 37 Table 13 EIPS assumptions, CCGT (auto-diesel) 38 Table 14 EIPS assumptions, CCGT (Fuel oil) 40 Table 15 Open-cycle combustion turbine, CEB Assumptions 40 Table 16 EIPS Assumptions, open-cycle combustion turbines 42 Table 17 Coal technology efficiencies in China 42 Table 18 Delivered cost of LNG 47 Table 19 LNG consumption 48 Table 20 Petcoke yield 49 Table 21 Petcoke v coal 50 Table 22 Platt’s petcoke spot price assessments 50 Sri Lanka: Environmental Issues in the Power Sector v ECA, RMA and ERM Contents Table 23 Sulphur balance if Petcoke is used in Puttalam power plant 51 Table 24 Technical characteristics of candidate technologies 53 Table 25 Economic characteristics of candidate technologies 53 Table 26 Technical characteristics of existing generation plant 54 Table 27 Economic characteristics of existing generation plant 55 Table 28 Parameters of a generic pumped storage power plant 57 Table 29 Purchase price from small power producers (contracts signed until 2006) 67 Table 30 Purchase price from small power producers (for contracts signed in 2009)68 Table 31 Parameters for NCRE tariff calculations and the levelised tariff option 69 Table 32 Summary of cases 71 Table 33 Energy share of each generating technology 73 Table 34 Capacity displaced by pumped storage generation 74 Table 35 Assumptions on the use of incandescent bulbs 75 Table 36 Estimated savings in energy 76 Table 37 Load forecast in the DSM case 76 Table 38 Estimated economic costs of present NCRE Tariffs 77 Table 39 Estimated economic costs of NCRE and candidate plants in the study 78 Table 40 Economic Benefits of NCRE 79 Table 41 Attribute values 88 Table 42 Comparison of GHG emissions from combustion against lifecycle emissions 93 Table 43 Historic growth of electricity sales and peak demand 101 Table 44 Household customer growth of CEB and LECO 102 Table 45 Historic data on average CEB selling price 103 Table 46 CEB’s fuel bill in 2007 (planned in 1992 vs actual) 106 Table 47 Comparison of Sri Lanka’s electricity prices with regional countries 107 Table 48 GHG emissions per capita 114 Sri Lanka: Environmental Issues in the Power Sector vi ECA, RMA and ERM Contents Table 49 Power densities, Sri Lanka hydro projects 116 Table 50 Power densities for Brazilian hydro projects 116 Table 51 GHG emissions in the LNG supply chain 119 Table 52 GHG emissions for coal technologies 120 Table 53 GHG emissions for coal and hydro 120 Table 54 CEB’s 2008 base load forecast 121 Table 55 CEB demand forecasting model – econometric analysis 123 Table 56 CEB’s 2007 base load forecast 124 Table 57 Estimated equation for domestic sales 126 Table 58 Estimated equation for domestic sales 127 Table 59 Consultant’s sales forecast 128 Table 60 Consultant’s gross generation and maximum demand forecast 129 Table 61 Sales forecast comparisons 130 Table 62 IEA price forecast 131 Table 63 CPC petroleum product import costs, 2008-2009 134 Table 64 CIF prices for gasoil and fuel oil 137 Table 65 Freight cost (Panamax, 60,000tonne size) 139 Table 66 Codes used in diagrams to describe plant types 151 Table 67 Summary of results and cost attributes with and without adjustments 153 Table 68 Organisations represented at the workshop 218 Figures Figure 1 Electricity sales forecast i Figure 2 Trade-off plot (illustrative only, not related to the Sri Lanka Study) vi Figure 3 Tariff trends vii Figure 4 Reference case generation and CO2 emissions vii Figure 5 SO2 emissions, reference case viii Figure 6 Population and stack-height adjusted SO2 emissions viii Sri Lanka: Environmental Issues in the Power Sector vii ECA, RMA and ERM Contents Figure 7 Generation shares, reference case ix Figure 8 GHG emissions versus economic cost x Figure 9 Trade-off between population and stack-weighted SO2 and system cost xi Figure 10 Energy security index versus system cost xii Figure 11 EIPS approach 3 Figure 12 Trade-off plot (illustrative) 9 Figure 13 Scenario assumptions 18 Figure 14 Electricity Demand 21 Figure 15 Global soil sensitivity to acidic deposition 23 Figure 16 Soil sensitivity to future acid deposition in Asia 23 Figure 17 Trends in SO2 levels in Colombo 26 Figure 18 Fitting FGD versus Paying for low sulphur coal 32 Figure 19 Cost Assumptions for combustion turbines 41 Figure 20 600 MW Super-critical coal vs. 300 MW sub-critical coal 44 Figure 21 Indo-Lanka interconnection 52 Figure 22 Daily load profile on a typical week-day (2007) 56 Figure 23 Demand profile and installed base load capacity in 2020 57 Figure 24 Screening analysis of selected thermal and hydro/NCRE options 61 Figure 25 Preliminary Screening Analysis of India-Sri Lanka Interconnection 62 Figure 26 Forecast energy share in the grid with NCRE target of 10% by 2015 66 Figure 27 Capacity additions in the reference case 72 Figure 28 Concerns about lower capacity factor of baseload power plants 73 Figure 29 Improved loading of baseload power plants with pumped storage 75 Figure 30 Economic costs of policy options 79 Figure 31 Reference case generation and CO2 emissions 80 Figure 32 Per capita GHG emissions 81 Figure 33 SO2 emissions, reference case 82 Sri Lanka: Environmental Issues in the Power Sector viii ECA, RMA and ERM Contents Figure 34 SO2 emission damage 82 Figure 35 Damage costs for particulates 83 Figure 36 Comparison of damage costs 83 Figure 37 Generation shares, reference case 84 Figure 38 Supply diversity index, reference case 84 Figure 39 Impact of LNG on the generation mix 85 Figure 40 Impact of LNG on the capacity diversity index 85 Figure 41 Revenue requirements 86 Figure 42 Tariff trends 86 Figure 43 Impact of discount rate on generation investment plan 89 Figure 44 Discounted CO2 emissions versus present value costs 90 Figure 45 Carbon shadow prices (combustion emissions only) 91 Figure 46 Undiscounted lifetime GHG emissions versus present value system costs91 Figure 47 Carbon shadow prices (lifecycle emissions) 92 Figure 48 System emission factors, kgCO2/kWh 92 Figure 49 Energy security index versus system cost 94 Figure 50 Trade-off between population and stack-weighted SO2 and system cost 95 Figure 51 Historic growth in sales (grid) 100 Figure 52 Sales growth rate 101 Figure 53 Comparison of Capacity Additions over 1993-2007 (1992 plan and actual)104 Figure 54 Comparison of Fuel Mix in Generation in 2007 (1992 plan and actual) 105 Figure 55 Summary of Life-Cycle GHG Emissions 118 Figure 56 Life-cycle GHG emission factors 118 Figure 57 Crude oil prices 133 Figure 58 Relative prices: Singapore fuel oil vs. ORB 133 Figure 59 Singapore v. Gulf gasoil prices (Platts, monthly averages) 134 Figure 60 Sri Lanka gasoil costs, fob 135 Sri Lanka: Environmental Issues in the Power Sector ix ECA, RMA and ERM Contents Figure 61 Sri Lanka fuel oil costs, fob 135 Figure 62 Gasoil price v. sulphur content 136 Figure 63 Freight costs for gasoil and fuel oil imports 136 Figure 64 Coal prices 138 Figure 65 Export coal prices in the Asia Pacific region 138 Figure 66 LNG prices, 2007-2009 140 Figure 67 Relative prices for LNG and coal 140 Figure 68 IEA forecast of relative prices 141 Figure 69 LPG v. other fuels 146 Figure 70 Nuclear fuel costs 148 Figure 71 Screening curve: nuclear 149 Abbreviations AFBC Atmospheric fluidised bed combustion CCGT Combined-cycle gas turbine CEA Central Environment Authority CEB Ceylon Electricity Board CDM Clean Development Mechanism (of UNFCCC) CEC Certificate of Environmental Clearance CFB Circulating fluidised bed CFL Compact Fluorescent Lightbulb cif Carriage insurance and freight CPC Ceylon Petroleum Corporation CRT Cathode ray tubes DSM Demand-side management ECA Economic Consulting Associates Sri Lanka: Environmental Issues in the Power Sector x ECA, RMA and ERM Contents EIPS Environmental Issues in the Power Sector (the current study) ERM Environmental Resources Management ESP Electrostatic precipitators FGD Flue-gas desulphurisation fob Free on board GAR Gross as received GNP Gross National Product GoSL Government of Sri Lanka HFO Heavy fuel oil HSFO High sulphur fuel oil IEA International Energy Agency IEE Initial Environmental Examinations IDC Interest During Construction IFI International Financing Institution IGCC Integrated gasification combined-cycle IPCC Intergovernmental Panel on Climate Change IPP Independent Power Producer JCC Japan Crude Cocktail JICA Japanese International Cooperation Agency LECO Lanka Electricity Company LKR Sri Lankan Rupees LNG Liquefied Natural Gas LTGEP Long-Term Generation Expansion Plan LTTE Liberation Tigers of Tamil Eelam MATA Multi-attribute Trade-off Analysis MPE Ministry of Power and Energy MoF Ministry of Finance NCRE Non-conventional renewable energy Sri Lanka: Environmental Issues in the Power Sector xi ECA, RMA and ERM Contents NEA National Environmental Act NTPC National Thermal Power Corporation (of India) OCGT Open-cycle Gas Turbine PAA Project Approving Agency (for environmental approvals) PM Particulate Matter ppm parts per million PPP Public-Private Partnership PS Pumped storage PSPP Pumped storage power plant RET Renewable Energy Technology RMA Resource Management Associates SPP Small power plant SPPA Small Power Purchase Agreement TOR Terms of Reference Trinco Trincomalee TSP Total suspended particulates UNFCCC United Nations Framework Convention on Climate Change WASP Wien Automatic System Planning WHO World Health Organisation Currencies $ in the text refers to US dollars $1 = 115 Sri Lankan Rupees Sri Lanka: Environmental Issues in the Power Sector xii ECA, RMA and ERM Executive Summary Executive Summary Context Between 1990 and 2008, electricity sales more than tripled, increasing from 2,394 GWh in 1990 to 8,349 GWh in 2008. Much of this growth derived from electrification, with the level of households having access to electricity increasing from 29% in 1990 to about 85% in 2009. Before the mid-1990s, the largest share of electricity was generated by hydropower plants but with most of the major hydroelectric potential already developed, non- hydropower energy sources were required to meet the growing demand for electricity. Despite plans to build coal-fired power plants as early as 1992, between 1992 and 2007 over 70% of all new capacity was provided by oil-fired open-cycle or combined-cycle plants, with low stacks and located in the densely populated Western Province. The unintended dominance of oil-fired plants was the result of several factors including public protest, lack of finance and weak investor interest in coal-fired generation. The delays in implementing cheaper power generating options and the dominance of small, expensive, oil-fired power plants led to high electricity costs and high electricity tariffs. It also led to increasing concentrations of SO2 in the air in Colombo until the year 2000, though this trend subsequently reversed. Sri Lanka’s first coal-first power plant is expected to be commissioned by the end of 2010 at Norochcholai, Puttalam, on the north-western coast. This is to be followed by the Trincomalee coal-fired power plant, expected to come on-line around 2014. With these additions, together with the Upper Kotmale hydropower project expected in 2011, oil will no longer dominate the fuel mix. We have reviewed and modified the Ceylon Electricity Board (CEB)’s forecast of electricity sales. This forecast is shown in Figure 1. Figure 1 Electricity sales forecast 45,000 40,000 35,000 30,000 25,000 GWh 20,000 15,000 10,000 5,000 0 2007 2008 2009 2010 2015 2020 2025 2030 Other 186 182 193 204 270 358 475 629 I&G 4,824 4,936 5,098 5,431 7,977 11,225 15,132 20,148 Domestic 3,219 3,230 3,597 3,946 6,298 9,671 14,018 19,860 Sri Lanka: Environmental Issues in the Power Sector i ECA, RMA and ERM Executive Summary CEB’s most recent long-term generation expansion plan has identified coal-fired power plants as the main least-cost option for base load operation to meet expected growth in demand. Between 2009 and 2022, 3,575 MW of new capacity is expected to be required and, of this, 3,155 MW or 88% would be coal-fired. By 2022, some 83% of electricity would then be generated by coal. As the power sector transitioned from one dominated by hydro to one dominated by oil so too the dominant environmental issues have shifted. Environmental concerns previously focused on the relocation of people displaced by hydropower reservoirs, safety and dam breaches, but then concerns switched to poor air quality resulting from oil-fired power plants in the heavily populated Colombo. If Sri Lanka transitions again to coal-fired power generation then the concerns will continue to focus on air quality and additionally on waste and greenhouse gas (GHG) emissions. Objectives of the study The World Bank has commissioned this study to assist the Government of Sri Lanka to identify a path toward sustainable power development1. The timing of the Report is important as Sri Lanka is about to embark on the development of coal-fired power plants over the coming years. Sri Lanka’s decision makers have a dilemma: coal-fired power plants offer the lowest cost but are regarded as environmentally unfriendly. But how much cheaper is coal-fired generation? How much more environmentally friendly are the alternatives and what impact would more environmentally friendly policies have on power sector costs and electricity tariffs? The answers to these questions have not previously been available. The purpose of this study is fill this gap and to provide quantitative analysis that will help decision-makers assess various power sector policy options in terms of the trade-offs between environment, cost and other impacts. The work is based on similar ‘environmental issues in the power sector’ studies conducted for India and other countries of the world. The study is not designed to make recommendations unless the options are unambiguously win- win; but more often than not, tradeoffs are required and ultimately Government must decide what it considers to be more important. Policies and technologies considered To answer questions relating to the costs and benefits of more environmentally options, a number of alternative policies and technologies were systematically analysed, in addition to coal-fired generation. The options, or combinations of options, analysed include: Demand-side management (DSM) intervention: The DSM policy that is analysed in the study goes beyond the on-going DSM interventions and examines, as an example, a ban on the sale of conventional incandescent 1 Though any views expressed in the Reports are those of the Consultant. Sri Lanka: Environmental Issues in the Power Sector ii ECA, RMA and ERM Executive Summary lightbulbs and the gradual phasing out of conventional bulbs as they need to be replaced. Non-conventional renewable energy (NCRE): NCRE technologies include a mix of small hydro, wind, biomass, agricultural and industrial waste, municipal waste, and waste heat. A policy was considered, consistent with Government strategy, to raise NCRE’s share of energy generation from the current level of 4.2% to 10% by 2015 using a mix of NCRE technologies. Conventional, medium-sized hydropower plants: There are four potential hydropower plants at Uma Oya (150 MW), Broadlands (35 MW), Moragolla (27 MW) and Ging Ganga (49 MW) which would not normally be chosen as part of a least-cost plan. Liquefied Natural Gas (LNG): LNG has relatively low emissions of SOx and particulates and no solid waste and gas burnt in an efficient combined-cycle power plant has low emissions of CO2. Supercritical coal-fired plants: Supercritical plants are more efficient than conventional (sub-critical) power plants and therefore produce lower emissions per kWh generated. No coal-fired power plants beyond the present commitments: In this option, no further coal-fired power plants would be allowed following the completion of the plants at Puttalam and Trincomalee, and demand will be met with oil or gas-fired plants. Pumped storage: A pumped storage plant or plants would help increase the utilisation of thermal power plants and reduce the part-loading and cycling (stopping and starting) of plants with the associated loss in efficiency. Other policies or technologies were also briefly considered including liquid petroleum gas (LPG), nuclear and some clean coal technologies2 but these were not considered to be realistic options and were omitted from the full analysis. Petroleum coke from a proposed refinery project could be used in a coal-fired power plant but the project is at an early stage and it is too early to judge whether it should be included as an option in an investment plan. Similarly, the Indo-Lanka interconnection may be attractive for imports from India to Sri Lanka during periods of low production from Sri Lanka’s hydropower plants and reverse flows during Sri Lanka’s off-peak demand periods, but it is too early to judge whether this investment is justified for cost or environmental reasons. Environmental regulations and standards Consideration was given to the existing and proposed emission standards for power plants in Sri Lanka. 2 Fluidised-bed combustion technologies. Sri Lanka: Environmental Issues in the Power Sector iii ECA, RMA and ERM Executive Summary Ambient air quality regulations were first introduced in 1994 and, most recently, tightened in August 2008. These are less stringent than World Health Organization (WHO) guidelines, particularly for particulate matter and SO2, but the Sri Lankan standards should not be regarded as being lax. Although ambient air quality and industrial effluent standards are enshrined in law, standards for source-specific atmospheric emissions are in draft form only and are thus presently used as a guideline to regulators in approving projects. Once formally issued by the Central Environment Authority (CEA), these standards will apply to new power plants but, until then, emissions are controlled through environmental impact assessment (EIA) regulations. In the case of the Puttalam coal-fired power plant, the EIA permit3 required the plant to use coal with a sulphur content of less than 0.65% sulphur, but it was not required to fit flue-gas desulphurisation (FGD) technology (though, as discussed below, the plant has voluntarily chosen to fit FGD). Air dispersion modelling prepared as part of the EIA process for the power plant confirmed that ambient air quality would satisfy national air quality regulations. To inform the final limits in the emission standards, a comprehensive study is presently under way. The latest draft recommendations for emission limits for coal- fired power plants include 800 mg/Nm3 for SO2, 650 mg/Nm3 for NOx and 100 mg/Nm3 for particulate matter. The draft emission limits for SO2 are effectively half those initially allowed at the Puttalam power plant. Even with the less stringent emission standards required at the Puttalam power plant, CEB chose to fit FGD in order to allow greater flexibility in sourcing of coal. The suppliers of low sulphur coal are considerably fewer in number and without FGD Sri Lanka would be less able to procure coal competitively. Additionally, security of supply could become a concern. The study considered the implications of the current and proposed stack emission standards for coal-fired power plant development and emissions and the cost premiums for low sulphur coal. The report concludes that both the existing and proposed standards, while not mandating the use of FGD, imply that it would be difficult to source coal with sufficiently low sulphur content to meet the standards unless FGD is fitted. The proposed standards, though tighter, do not therefore have very significant cost impacts4. Coal-fired power plants in the study are therefore all assumed to be fitted with FGD and the FGD units are assumed to be operated to satisfy the new draft emission standards. 3 Certificate of Environmental Clearance. 4Though the new standards do imply that the FGD units would be operated at higher capacity factor than they would otherwise have done with the emission levels implied by the EIA permits for Puttalam Sri Lanka: Environmental Issues in the Power Sector iv ECA, RMA and ERM Executive Summary Approach to the analysis The alternative policy and technology options are analysed using generation simulation and planning software5. Such software normally chooses the optimum least-cost6 investment plan based on cost minimisation criteria and in order to analyse alternative technologies or policies that are not least-cost the model must be ‘forced’ to accept these options. The parameters of interest – derived using the planning software – are called attributes and in this study the attributes examined include: Cost per kWh (levelised economic cost7) CO2 emissions (both undiscounted and discounted lifetime emissions) SO2 emissions (discounted and weighted as described below) An index8 of generation mix representing energy security Average consumer tariff per kWh9 It is important that the attributes are defined on a meaningful scale. A tonne of CO2 is a meaningful parameter by itself because a tonne of CO2 emitted from a coal-fired power station has an identical impact on global warming as a tonne emitted by a diesel bus or an LPG stove. However, a tonne of SO2 is not a meaningful parameter by itself because a tonne of SO2 emitted from a power station with a high stack does not lead to the same damage to health as a tonne of SO2 emitted from a diesel bus. SO2 emissions must therefore be adjusted and in this case we use population- and stack height-weighted SO2 emissions to reflect the dispersion of SO2 and the size of the population that may be affected. With the attributes calculated for each scenario, their values can be plotted as a trade-off plot. Figure 2 illustrates the concept and shows the plot of economic cost per kWh versus emissions (say GHG). 5In this case, the analysis used Wien Automatic System Planning (WASP) developed by International Atomic Energy Agency (IAEA) and Argonne National Laboratory. 6 Least-cost in this context is the investment that achieves the lowest total present-valued economic costs over the planning period (to 2028) including capital, fuel and operating costs. The fuel and operating costs are based on a simulation of the optimal dispatch of plants. The model can minimize costs that include allowance for some environmental damage cost but in this analysis the cost minimisation excludes such costs in order the costs and benefits to be explicitly estimated. 7 Present value of the total costs of generation divided by the present value of the electricity sold. 8 Herfindahl index. 9 Levelised average over the study period. Sri Lanka: Environmental Issues in the Power Sector v ECA, RMA and ERM Executive Summary Figure 2 Trade-off plot (illustrative only, not related to the Sri Lanka Study) Drawing horizontal and vertical lines from the reference case we obtain four quadrants. Options or cases in the top right quadrant lose on both counts (they have higher costs and higher GHG emissions) while options in the bottom left would be win-win (lower costs and lower emissions). To the bottom right and top left are options that involve a trade-off relative to the baseline. The top left quadrant reflects lower emissions but higher costs while the bottom right shows lower costs and higher GHG emissions. Figure 2 also illustrates the “trade-off curve� in a typical case. This shows the set of options that cannot obviously be beaten by other options – these points have no other points below them and to their left. In this example, the DSM option is clearly better than the baseline (and therefore the baseline is not included in the trade-off curve). The renewable energy option has lower emissions than the DSM option, but has higher costs and this is therefore included in the trade-off curve. Similarly, the option without pollution controls is lower cost but has higher emissions and is included in this illustrative trade-off curve. Results of the analysis – reference case The Report confirms that coal-fired power plants, complying with Sri Lanka’s environmental regulations, should be the technology selected if cost minimisation is the primary objective of policy. Figure 3 shows the retail tariff trend10 and shows a substantial fall in the level of tariffs required to cover aggregate system costs in the reference case. Although tariffs averaged only 12.2 cents/kWh in 2008, the analysis estimates that they would need to be approximately 15 cents/kWh in 2009 to cover system costs but, with the reduction in costs predicted, this would fall to less than 10 cents/kWh from 2015 onwards. 10 In this diagram, the tariff trend is superimposed on the fuel cost (expressed per kWh of thermal generation), and the renewable energy tariff, expressed per kWh of renewable energy generation). Sri Lanka: Environmental Issues in the Power Sector vi ECA, RMA and ERM Executive Summary Figure 3 Tariff trends The analysis shows that increased use of coal for power generation, which by 2028 would account for 86% of energy (Figure 4), would lead to a ten-fold increase in CO2 emissions. Figure 4 Reference case generation and CO2 emissions When measured in per capita terms, the increase is from 0.17 tonnes/capita to 1.3 tonnes/capita by 2028. It must be noted, however, that compared to emissions in the rest of the world, even a tenfold increase in Sri Lanka barely registers in global comparisons with, for example, China (4.6 tonnes/capita) and the US (19 tonnes/capita). Other examples in 2007 include India (1.2 tonnes per capita), Brazil (1.8 tonnes per capita) and Vietnam (1.2 tonnes per capita). The analysis also shows that increased use of coal will lead to a doubling of SO2 emissions, as shown in Figure 5. Emissions from heavy oil projects decrease as these are retired, but this decrease is more than offset by emissions from coal-fired plants. The increase in emissions is, however, significantly less than the four-fold increase in electricity sales that is forecast over this period – leading to a halving of the SO2 emissions per kWh sales. Sri Lanka: Environmental Issues in the Power Sector vii ECA, RMA and ERM Executive Summary Figure 5 SO2 emissions, reference case But as noted earlier, the parameter “tonnes of SO2� is not meaningful by itself because it bears little relationship to likely impacts. As soon as emissions are weighted by population and adjusted for stack height, the picture changes significantly as shown in Figure 6. At present the bulk of SO2 emissions are produced from plants burning heavy fuel oil with low stacks, no FGD controls, and located predominantly in the most heavily populated Western Province. As the Puttalam units, with 160 meter high stacks, located in a less densely populated area, and fitted with FGD, enter service, the operation of the oil-fired plants decline dramatically. Beyond 2020, there is a shift of coal-fired plants to the east coast, with a yet lower population density and an almost complete phasing out of generation at the heavy fuel oil plants in the Western Province. Figure 6 Population and stack-height adjusted SO2 emissions Sri Lanka: Environmental Issues in the Power Sector viii ECA, RMA and ERM Executive Summary With respect to security of supply, the analysis shows that coal’s share of the energy mix will increase leading to a decline in diversity of fuels. Figure 7 shows the generation shares used in the supply diversity attribute. Note the inexorable increase in coal share, rising from the present zero to 59% by 2015, and 86% by 2028. Figure 7 Generation shares, reference case Thus the supply diversity index rises in the early years as the coal share increases, with the greater diversity reached in 2015. But as the coal share rises further, to dominate the picture by the end of the planning horizon, diversity decreases. With 86% of generation in one technology/fuel, diversity is smaller than the present situation, where two energy sources dominate (oil and hydro). Multi-attribute trade-off analysis CO2 emissions: Figure 8 shows the plot of economic cost per kWh versus CO2 emissions for the Sri Lanka study. As expected, the scenarios involving additional renewable energy and LNG involve trade-offs – this shows that lower CO2 emissions can only be achieved at higher cost through hydropower, NCRE or LNG, or a combination of these three (the ‘green’ case) or by placing a moratorium on the development of any further coal-fired power plants beyond those committed at Puttalam and Trincomalee. In the LNG case, for example, levelised average electricity tariffs to end-users would, without carbon credits, need to be nearly 15% higher than they would be in the reference case (but they would still be lower than today’s average tariffs in real terms). Credits for the reduction in GHG emissions could mitigate this impact on costs to some extent, but costs and tariffs would still have to rise considerably relative to the reference scenario. NCRE would require tariffs to be 11% higher than Sri Lanka: Environmental Issues in the Power Sector ix ECA, RMA and ERM Executive Summary in the reference case but carbon credits, if any, would not be used to mitigate the impact on end-user electricity tariffs11. The analysis can be used to estimate the “carbon shadow price� for the options that reduce CO2 emissions. The carbon shadow price is roughly equivalent to the price that would have to be offered to Sri Lanka, for example through the Clean Development Mechanism (CDM) of UNFCCC, to make it financially attractive for Sri Lanka to adopt low CO2 emission options. The medium-sized hydropower projects have, by far, the lowest carbon shadow price at around $37/tonne, and this is the only option that approaches the carbon price currently observed in global carbon markets.12 The carbon shadow price for LNG and NCRE, at $86/tonne and $87/tonne, are much higher than current international market prices. Figure 8 GHG emissions versus economic cost Local air quality: The trade-off between the cost and health impact (a population and stack height weighted index is used as a proxy for the health impacts on local populations) is shown in Figure 9. Surprisingly, hydro, LNG, and forcing-in supercritical coal-fired plants (sooner than the reference would provide by itself) are in the lose-lose quadrant – with higher costs and poorer local air quality. For reasons explained below, the poorer air quality arises because these three cases lead to increased production from the oil-fired plants located in the densely populated west. 11 Carbon credits for NCRE projects, if any, are kept by the developer. 12 World Bank, State and Trends of the Carbon Market 2009, May 2009. Sri Lanka: Environmental Issues in the Power Sector x ECA, RMA and ERM Executive Summary Figure 9 Trade-off between population and stack-weighted SO2 and system cost The poorer air quality in the case of medium-sized hydropower in Figure 9 arises, unfortunately, because the commissioning of these plants would delay coal-fired plants and perversely this would lead to increased production from the oil-fired plants located in the densely populated west. In the supercritical case (commissioning supercritical coal-fired plants earlier than were otherwise selected in the reference case), increased production from oil-fired plants is estimated by the model because supercritical units are necessarily 600 MW and are large relative to Sri Lanka’s peak demand. Because of part-loading constraints, this leads to the greater use of the smaller oil-fired plants which are, unfortunately, located in the densely populated west. The poorer air quality in the LNG case in Figure 9 arises because the LNG plants are assumed to have a higher variable fuel cost than some of the oil-fired plants, leading to greater operating hours of the oil-fired plants and increased emissions in the densely populated west. In reality, the LNG plants would have take-or-pay obligations which would mean that the LNG plants would be operated ahead of oil- fired plants in the merit order and local air quality could be slightly better than in the reference case. The LNG option would then be in the trade-off quadrant IV but the cost attribute for LNG would then be even worse than shown in Figure 9. Energy security: The tradeoffs between system cost and average energy security are shown in Figure 10. The general pattern corresponds to the trade-offs between cost and GHG emissions, though pumped storage now lies in the win-win quadrant rather than the trade-off quadrant-II. Indeed, all options improve generation diversity over the reference case. The ‘green’ scenario (LNG + medium hydro + NCRE) has the highest generation mix diversity. Sri Lanka: Environmental Issues in the Power Sector xi ECA, RMA and ERM Executive Summary Figure 10 Energy security index versus system cost Sensitivity to fuel prices: The cases analysed above are based on an international oil price of $75/bbl, a price for coal delivered to Trincomalee of $102.7/tonne, and a delivered price for LNG, excluding terminal costs in Sri Lanka, of $9.5/mmbtu. Sensitivity analyses reveal, not surprisingly, that system costs and the baseline shift upwards if international oil prices are, instead, $125/bbl and if oil products, coal and LNG prices increase correspondingly. However, WASP continues to choose coal-fired power plants in the least-cost plan in preference to medium-sized hydro or NCRE. This implies that there would continue to be a trade-off between cost and environmental impact, even for the lower-cost environmentally-friendly options. While the analysis was not repeated to reveal a complete new set of trade-off curves for a high fuel cost scenario, it is clear that higher energy prices would lead the trade-offs for DSM, medium size hydro, and NCRE options to be less costly. Sensitivity to the discount rate: The cases analysed above use an economic discount rate of 10%. The WASP model did not select medium-scale hydropower plants at this discount rate in the reference case but when the discount rate is 6% then the four medium-scale hydro plants are selected as least cost. This implies that if a lower discount rate is adopted then the development of medium-sized hydro would not lead to a trade-off between system costs and environmental impacts. Implications for decision makers The objective of the analysis has been to understand the trade-offs between various future investment and policy paths. In analysing these trade-offs we have considered, in some detail, possible investment plans. While these investment plans have been analysed rigorously, they should not be interpreted as definitive investment plans. Further work is necessary to analyse all of the options, including those that have not been considered fully in this analysis, and develop a full plan for electricity sector investment and policy. The EIPS analysis confirms that coal-fired power plants, complying with Sri Lanka’s environmental regulations, should be the technology selected if cost minimisation is the primary objective of policy. The re-orientation of the fuel mix toward coal-fired power generation would help lower average tariff requirements in real terms by more than one third by 2015 relative to today. Sri Lanka: Environmental Issues in the Power Sector xii ECA, RMA and ERM Executive Summary While the analysis shows that increased use of coal for power generation in Sri Lanka will lead to a significant increase in CO2 emissions, in terms of emissions per capita, Sri Lanka’s CO2 emissions in absolute terms and per capita terms will remain small compared to global averages. In terms of local air quality, the analysis shows that while increased use of coal will lead to a significant increase in SO2 emissions the increase in emissions is half the increase in electricity sales so that SO2 per kWh consumed falls substantially. Additionally, when account is taken of the location of the coal-fired power plants, the emission control technologies, and the height of their stacks compared with the oil-fired plants today, the population and stack-weighted emissions of SO2 are significantly lower than those today. In terms of security of supply, the analysis shows that coal’s share of the energy mix would increase substantially to 86% by 2028, implying a worsening of diversity compared with today’s mix of fuels. DSM policies aimed at encouraging compact-fluorescent lightbulbs have been implemented in Sri Lanka and the penetration rate is already relatively high. The trade-off analysis reveals that further DSM policies could be win-win - reducing emissions of SO2 and CO2, improving security of supply, and lowering costs. The DSM policy analysed in the study was, however, indicative and would need to be properly evaluated and prepared before this, or other DSM policies, are introduced. Although DSM policies will not avoid the need for policy makers to make choices between coal and other energy sources/technologies, DSM policies could delay some investments and should be analysed further and a full DSM strategy developed. Attractive feed-in tariffs are available in Sri Lanka that are designed to encourage NCRE projects and meet Government targets for NCRE to provide 10% of generated energy by 2015. Analysis of this policy is shown to imply a trade-off between higher economic costs on the one hand and improved environment and security of supply on the other. The NCRE policy case examined includes a mix of technologies some of which are likely to be win-win (particularly small hydro, agro- industrial waste and waste heat) while others involve trade-offs. However, each of these technologies individually has limited potential capacity and energy and in order to achieve the aggregate 10% target some of the more costly technologies would need to be developed as well as the cheaper win-win technologies. Overall, Government’s NCRE target of 10% is estimated to lead levelised average electricity tariffs to be higher than in the reference case (by nearly 8%). Measured in terms of a subsidy to avoid CEB incurring additional costs above the reference case, the subsidy would need to be approximately $82 million per year. The analysis shows that the price currently available for CDM credits internationally would not be sufficient to offset the additional costs of NCRE in aggregate (but would probably be sufficient to offset the extra costs of some of the cheaper NCRE technologies such as small hydro and agro-industrial waste). However, the benefits of CDM credits would not flow to CEB or to electricity consumers to offset higher electricity costs resulting from the feed-in tariff policy. Sri Lanka: Environmental Issues in the Power Sector xiii ECA, RMA and ERM Executive Summary While the bundle of NCRE technologies involves a trade-off, it is clear13 that a policy that focused particularly on some of the more attractive renewable energy technologies - such as small hydro, agro-industrial power and waste heat – would involve only moderate trade-offs or would be win-win (waste heat). While the EIPS analysis was not designed to identify the optimum NCRE policy, it does suggest that Sri Lanka should give a high priority to the development of some NCRE options in particular. The four medium sized hydropower plants, while implying higher costs than the least-cost investment plan, are shown by the analysis to be a relatively low-cost way to reduce emissions of CO2 and improve security of supply. The cost of reducing CO2 using medium-sized hydro is estimated to be $37/tonne of CO2 which is not too far from the current global carbon market prices. If CDM credits can be obtained and used to offset the extra costs of hydropower then it implies a relatively small net impact on electricity tariffs. Even without CDM credits then the impact on tariffs would be relatively small at only 1% (or, alternatively, a subsidy from somewhere of $14 million per year). Perversely, however, the analysis shows that there could be a negative impact on local air quality because the hydropower plants would delay commissioning of coal-fired plants located in the east and, relative to the reference case, increase production from oil-fired plants with low stacks located in densely populated areas in the west. Of the alternative technologies considered, LNG is found to be the least attractive way to lower CO2 emissions. Without GHG emission reduction credits, levelised average electricity tariffs would need to be 16% higher than in the reference scenario – though with CDM credits the impact on tariffs would be reduced. Without CDM credits, then CEB’s costs would be $175 million per year higher with this option. LNG also has significant upside risk if oil prices rise whereas NCRE carries no fossil fuel price or volatility risk. It does not make sense to implement LNG (or even wind and biomass that are part of the NCRE scenario) if one does not first implement much cheaper ways of achieving the same objective – medium sized hydropower as well as small hydropower and some other NCRE technologies. If, as is likely, Sri Lanka continues to invest in coal-fired power plants then, relative to sub-critical coal-fired power plants, super-critical is likely to be win-win. Super- critical technology should be adopted as soon as the size of the power system permits in place of sub-critical coal-fired power plants. Pumped-storage was generally shown in the analysis to be win-win but its environmental impact is relatively minor. This option should be investigated further as a part of the reference scenario. A moratorium on any new coal-fired plants beyond the plants under development at Puttalam and Trincomalee would, in combination with least-cost planning, lead CEB to choose oil-fired power generation capacity. Compared with the reference case, this would reduce emissions of CO2 and improve local air quality and security of supply. This option would be costly, though not as costly as the LNG option. Levelised average tariffs with this option would be just under 10% higher compared with the reference case, similar to the NCRE option but slightly less than the LNG option. As with LNG it might qualify 13 It is clear from the unit cost data. Sri Lanka: Environmental Issues in the Power Sector xiv ECA, RMA and ERM Executive Summary for CDM credits that could partly offset the impact on tariffs, but may be more difficult to justify. Sri Lanka: Environmental Issues in the Power Sector xv ECA, RMA and ERM Introduction 1 Introduction 1.1 Background The World Bank has commissioned this study to assist the Government of Sri Lanka (GoSL) in identifying a path to sustainable power development. Ideally, the optimal path will minimise the environmental impacts of generation while meeting demand in a least-cost manner. In reality, there is a trade-off between these two goals. Minimising environmental impacts often comes at a cost. To parameterise these trade-offs, this study examines a number of alternative paths the generation sector can take over the next 20 years, with the paths characterised by various options available to the sector. The outcomes of these alternative paths in terms of cost, environmental impact, and security of supply are then captured such that they are readily comparable between the various paths. The end result is a study offering the GoSL a menu of paths whose trade-offs are readily comparable and upon which GoSL can base its decision in choosing its path. What the study will not do is identify the correct decision, for this will depend on the priorities of the Government. In this regard, a key priority of GoSL is to increase the level of access to grid-supplied electricity while enhancing the corresponding power supplies. Currently, approximately 83% of households have access to electricity. Although the economic crisis has dampened expectations of demand growth, particularly in the near-term, demand is forecast to grow at a rate of between 5% and 6.5% in the decade following 2009. GoSL plans to meet the majority of this expansion of demand and enhancement of supply through the development of coal-fired power generation. By 2015, coal-fired generation is expected to make up 57% of energy supplied to the grid, a level which today sits at zero. Generation from this fossil fuel source will increase as the share of production from hydropower declines, although capacity from non-conventional renewable sources is expected to make up some of this fall. As reliance on coal increases, so too will the potential for environmental degradation. GoSL is, however, in a somewhat fortuitous position. With coal generation still to be developed, GoSL can shape this development rather than attempt to alter it after the fact through costly end of pipe solutions. Empirical evidence shows that the environmental impacts of coal based power development can be better managed if compliance measures are considered at the planning stages. Hence, to inform these considerations, the main objectives of this study are to: (i) Identify the environmental consequences of the power sector in general, with particular focus on coal-based power generation and strategies for mitigating adverse environmental consequences within a power system planning framework; and (ii) Develop a Regulatory Framework for Environmental Management for the power sector in Sri Lanka. Sri Lanka: Environmental Issues in the Power Sector 1 ECA, RMA and ERM Introduction The approach, described in detail in Section 1.2, utilised to achieve these objectives is a multi-attribute trade-off analysis, the results of which will allow policy-makers to easily compare the costs of various policy options against their environmental consequences. The primary environmental parameters include emissions of SO2 and CO2, although additional local environmental impacts are also captured. Economic efficiency is included and captured by the present value of economic system costs, as provided by the optimal capacity expansion analysis. Finally, security and diversity of supply are reflected by an index of generation mix14. To mitigate environmental consequences, options considered include: inter-fuel substitution, considering both domestic and imported fuel possibilities, including LNG, coal and renewable energy sources; non-conventional renewables; demand-side management (DSM); strengthening environmental standards; sector reforms; and alternatives to coal. To ensure robustness of policy options to uncertainty, the analysis also captures factors beyond the immediate control of policy-makers in the power sector, such as world coal, oil, and gas prices, and the availability and sources of coal and gas imports. 1.2 Approach To allow decision-makers in Sri Lanka to assess the trade-offs of the various power sector policy options considered, this study utilises a multi-attribute trade-off analysis. Modelled on a similar ‘environmental issues in the power sector’ (or EIPS) study conducted for India, the primary purpose of multi-attribute trade-off analysis is to project the costs and environmental externalities of various outcomes and then compare them via meaningful parameters capturing the trade-offs between the two. As various policy choices will impact demand, investment and generation, the analysis includes a number of components which must all be considered when assessing the impact of a policy. These components and the process by which they link together are illustrated in Figure 11 below. 14 A Herfindahl index. Sri Lanka: Environmental Issues in the Power Sector 2 ECA, RMA and ERM Introduction Figure 11 EIPS approach DSM 1. ELECTRICITY DEMAND FORCAST 7. FINANCIAL INTER-FUEL ANALYSIS SUBSTITUTION 2. LEAST COST EXPANSION PLAN RENEWABLE ENERGY OPTIONS 8. TRADE-OFF 3. COAL ANALYSIS DEMAND COST ASH MANAGEMENT 4. COAL TRANSPORT IMPACTS AND ENVIRONMENTAL MITIGATION IMPACT MITIGATION OPTIONS FOR POWER 5. MITIGATION DEVELOPMENT MEASURES (POWER PLANTS) 6. ENVIRONMENTAL EFFECTS Specifically, the first step in this approach is to develop a forecast of electricity demand, a full discussion of which is provided in Section 3.5. Once a demand forecast is developed, it is fed into a power system planning tool to determine the least cost schedule of investment and dispatch. Optimisation is based on both financial and economic costs, with financial costs covering inputs such as commodity prices and other administered costs such as transport, etc. Economic costs are utilised to determine the opportunity costs of resources, factors critical to investment decisions, and to ensure that the impact of standards, regulations and laws governing the use of the environment are properly captured in the optimisation. To derive the actual investment and dispatch schedule, the power system planning tool performs a dynamic programming optimisation that considers not only these financial and economic costs but parameters such as reserve margins, reliability constraints and loss of load probability. Sri Lanka: Environmental Issues in the Power Sector 3 ECA, RMA and ERM Introduction Outputs such as generation, and thus demand for primary fuels, from the optimal configuration are next utilised to produce environmental balances and financial accounts. Environmental balances include air emissions, solid waste, etc., while the financial accounts include revenue requirements necessary to meet the investment program and operating costs. The resultant set of financial, economic and environmental values form the crux of the trade-off analysis. The goal of this multi-attribute trade-off analysis is to allow the numerous impacts of the power sector (e.g., financial, environmental, etc) to be readily comparable across different paths the power sector can take. In this sense, objectives beyond economic efficiency can be considered when making policy. Hence the set of financial and environmental accounts need to be converted to quantitative indicators capturing the various objectives of power sector development. These objectives and their corresponding indicator are: Economic efficiency: levelised economic cost/kWh; Climate change: undiscounted and discounted lifetime CO2 emissions; Local environmental impacts: population- and stack height-weighted SO2 emissions; Energy security: Herfindahl index of generation mix (explained below); and Consumer Impact: levelised average consumer tariff, Rs/kWh. Formally entitled attributes, these are discussed in detail in the following section. The key point for this discussion is that, once the objectives of the decision-makers are identified, the financial and environmental accounts can be converted to quantitative proxies that allow the alternative paths to be readily compared against one another via trade-off curves. The trade-off curves for this study are presented in Section 8. 1.3 Attributes The activities of the power sector impact individuals, the economy and the environment in multiple and complex ways. The term attributes is used to describe the quantitative impacts of these activities. Defined to capture the objectives of the government and/or decision-makers, it is critical that these be defined on some meaningful scale of measurement. For example, tonnes of CO2 is a meaningful scale as a tonne of CO2 emitted from a coal power station has an identical impact to a tonne emitted by a diesel bus. Conversely, kilograms of SO2 is not a meaningful scale because a tonne of SO2 emitted from a power station is not equivalent to a tonne of SO2 emitted from a diesel bus. Additionally, how much weight is given to each attribute cannot be answered by analysts, for that is the preserve of Government. What the analyst can provide is the quantification of the trade-offs between the objectives, so that decision-makers can make choices properly informed about the choices to be made. While there are some options that are unambiguously win-win (meaning that a particular option performs Sri Lanka: Environmental Issues in the Power Sector 4 ECA, RMA and ERM Introduction better than an alternative on more than one objective), more often than not, tradeoffs are required. In the past, the principal attribute in Ceylon Electricity Board’s (CEB) generation planning studies has been the present-value of system costs to meet the specified load forecast (under an exogenously specified reliability criterion). However in the present study this attribute is complemented by calculation of other attributes that reflect important objectives in the planning process such as minimising GHG emissions, improving energy security, minimising local environmental impacts – attributes which are difficult to monetise and include in the economic analysis. As noted in Section 4.8, where such damage cost estimates are discussed in more detail, the literature reveals uncertainties of several orders of magnitude. That said, each of the attributes considered in this study is described below. 1.3.1 Economic efficiency The attribute that best captures the objective for economic efficiency is the present value of economic system costs, as provided by the optimisation model for optimal capacity expansion. The WASP model – Wien Automatic System Planning package – has been used for many years by CEB for generation expansion planning. The critical assumption here is the discount rate, for which the practice is to use the opportunity cost of capital as set by the Government (10%). 1.3.2 CO2 emissions The main issue in the definition of the CO2 emission attribute is whether or not to discount the emissions at the same rate as used in the economic modelling. Some recent studies use the total undiscounted emissions over the planning horizon, others use discounted emissions (which has the further advantage that the methodology for end-effect corrections are of less importance). Discounting CO2 emissions at the same discount rate as used for the economic attribute has the main advantage that the slope of the line connecting any two points (scenarios) on a trade-off plot of NPV versus CO2 emissions represents the carbon shadow price. This study therefore uses the discounted attribute for the multi-attribute analysis (though for sake of comparison, undiscounted lifetime emissions are also reported in the Annex of results). The detail of the actual calculation of CO2 emissions is discussed in Section 3.4 (Carbon Accounting). 1.3.3 Local environmental impacts For some time CEB has calculated and reported emissions of local air pollutants (particulates, SOx, NOx) as part of its generation planning studies, denominated in tonnes/year. However, while easy to calculate, it is doubtful that gross emissions of such pollutants measure anything useful about actual environmental impacts. Indeed, as described in Section 4.8, the impact of SO2 emissions will vary depending on the height of the point at which SO2 is discharged from its source. Hence, a kg of particulate matter emitted by the barge-mounted fuel oil-fired generator in Colombo Harbour without the benefit of a tall stack has a much greater health impact than a kg of particulate matter emitted at a remote coal-fired power station with a tall stack. Sri Lanka: Environmental Issues in the Power Sector 5 ECA, RMA and ERM Introduction Therefore, to be meaningful, local air emissions should be population and stack-height weighted.15 Ideally, one should assess actual damage costs and include them in the benefit cost analysis: but this is often quite difficult, and subject to large uncertainties. The extent to which damage costs can be assessed in Sri Lanka is discussed further in Section 4.8. 1.3.4 Consumer impact The impact on consumers is measured by the change in average consumer tariff, levelised over the planning horizon. This is calculated on the basis of the change in CEB’s revenue requirements (relative to the reference case), as levelised Rs/kWh. The revenue requirements are calculated on the basis of financial costs to CEB, which differ from economic costs by taxes and duties. 1.3.5 Displaced population The Puttalam coal-fired power plant caused the displacement of 73 households, irrespective of their ownership of the land. A new housing scheme has been built to accommodate 80 families, and provided with housing with electricity service and water, and basic furniture. In addition, agricultural land has been provided in the vicinity. In the Trincomalee coal-fired power plant site, it is unclear how many families had to be relocated. The site was declared a high-security zone, which means the inhabitants had to be compulsorily relocated outside the zone, whether the power plant is built or not. The four medium scale hydro projects in the candidate list have negligible reservoir areas compared with the large scale projects. However, owing to the pond created as a result of a weir, there can be some displacement of people. As the feasibility studies are still in progress, it is too early to assess the displacement effect of these candidate projects. 1.3.6 Energy Security and supply diversity Energy security is an objective that is increasingly discussed (most recently this features prominently in the IEA World Energy Outlook reports by the International Energy Agency (IEA)).16 However, quantifying this objective is difficult because it is not always clear how the concept of “energy security� distinguishes between diversity of supply and dependence on imports. The paradox is that increased supply diversity sometimes means greater, not less, dependence on imports. The greater the number of different fuel sources, the more robust will be the power generation system as a whole. Even an all-hydro system such as Nepal is subject to the uncertainty of hydrology, 15Of course, this is quite different to the case of GHG emissions, for which it does not matter at all where the emission occurs. 16 See e.g., International Energy Agency, World Energy Outlook 2007: China and India Insights. Sri Lanka: Environmental Issues in the Power Sector 6 ECA, RMA and ERM Introduction which could be hedged by imports of thermal power from India, which would increase the robustness of electricity supply through increased imports.17 Sri Lanka’s belated commitment to coal generation heeds these lessons of the international experience. Coal is not only cheaper than oil, but because the potential suppliers (South Africa, Australia, Indonesia) are different to the suppliers of auto- diesel (Singapore spot market, Gulf States), the geopolitical risk of supply disruptions is diversified. One way of quantifying the diversity of the generation mix is to calculate its Herfindahl index, a measure widely used to describe the concentration of firms in an industry, H, and thus as an indication of the amount of competition among firms. The index H calculates simply as the sum of squares of the market (generation mix resources) shares s as follows: H = ∑ si2 n The lower the value of H the greater the diversity of fuels. Since the price (and availability) of all petroleum products are highly correlated, all oil based generation technologies can be treated as a single resource. Table 1 shows how the diversity of the Sri Lanka generation mix has varied over time: the value of H peaked in 1990 at 0.65 when hydro accounted for the highest share (thereby exposing Sri Lanka to hydrology risk). H declined by 2007 as autodiesel thermal generation increased (to 0.45), and will decline further still with the introduction of coal (0.33 by 2012) and further still were one to add 400 MW of wind (to 0.26). The index can be denominated in either energy or capacity. Both have merits and weaknesses and both are very approximate measures of supply security: installed capacity that might normally be used for mid-merit or peaking can, in the event of supply disruptions or price spikes for coal or LNG, be used to a greater extent than is normally planned. Using installed capacity mix as the measure of security partially captures the flexibility of the system in the face of supply disruptions. However, installed capacity would less accurately capture the financial consequences of supply disruptions. 17 The October 1973 oil embargo against the US first exposed the strategic dangers of excessive reliance on imported fuel, and the failure of the United States to reduce its dependence on imported oil is viewed by many as an important geopolitical disadvantage. Excessive dependence on imported fuels is widely seen as undesirable, although there is little evidence that Japan’s emergence as a leading economic power, or Singapore’s success among smaller nations, has been constrained by having to import all fossil fuels. On the other hand, Nepal’s policy of energy autarchy has made it very difficult to develop Nepalese hydro peaking export projects, because for its part, India would like to export surplus baseload thermal power from its eastern region – a trade that would benefit both countries. Indeed, both China and India see increasing fuel imports (coal, LNG and pipeline gas) as essential to their continued economic development. Sri Lanka: Environmental Issues in the Power Sector 7 ECA, RMA and ERM Introduction Table 1 Capacity shares Installed Capacity, MW (Capacity Shares) 1970 1980 1990 2000 2007 2012 2012 +coal +renewables Conventional 175 (66%) 315 (75%) 997 (78%) 1117 (61%) 1187 (49%) 1187 (39%) 1187 (33%) hydro Oil 73 (28%) 90 (21%) 266 (21%) 685 (37%) 1115 (46%) 1115 (37%) 1115 (31%) Small hydro 17 (7%) 17 (4%) 21 (2%) 33 (2%) 133 (5%) 133 (4%) 250 (7%) Solar PV 0 (0%) 0 (0%) 0 (0%) 0 (0%) 0 (0%) 0 (0%) 0 (0%) Biomass 0 (0%) 0 (0%) 0 (0%) 0 (0%) 2 (0%) 0 (0%) 0 (0%) Wind 0 (0%) 0 (0%) 0 (0%) 3 (0%) 3 (0%) 0 (0%) 400 (11%) Coal 0 (0%) 0 (0%) 0 (0%) 0 (0%) 0 (0%) 600 (20%) 600 (17%) LNG 0 (0%) 0 (0%) 0 (0%) 0 (0%) 0 (0%) 0 (0%) 0 (0%) Imported 0 (0%) 0 (0%) 0 (0%) 0 (0%) 0 (0%) 0 (0%) 0 (0%) electricity Total 265 (100%) 422 (100%) 1284 (100%) 1838 (100%) 2440 (100%) 3035 (100%) 3552 (100%) Herfindahl- 0.52 0.60 0.65 0.51 0.45 0.33 0.26 index Source: Generation mix data is based on CEB Generation Expansion Plan 2008 1.3.7 Trade-off curves Trade-off curves are simply XY plots of attributes, two at a time. Typically one shows quadrants relative to the baseline, into which fall the options as may be defined by perturbations of that baseline. Figure 12 shows such an (illustrative) plot. Sri Lanka: Environmental Issues in the Power Sector 8 ECA, RMA and ERM Introduction Figure 12 Trade-off plot (illustrative) Quadrant I contains solutions best described as “lose-lose�, or rather those options that have higher emissions and higher costs. Typical options in this quadrant would be an option involving fossil fuel price subsidies (assuming the baseline is at economic prices), or not sub-critical coal units (if the baseline includes supercritical units). Quadrant II contains solutions involving tradeoffs – costs decrease, but emissions increase. No flue-gas desulphurisation (FGD) or pumped storage would be options that typically occupy this quadrant. Quadrant III contains solutions that are “win-win�, of which DSM, or reduction in T&D losses, are typical examples. Here both attributes improve outcomes, with both lower emissions and lower economic costs. Quadrant IV again contains options that require a trade-off – emissions decrease but only at increased cost. Renewable energy options, and substitution of coal by LNG, are typical options to be found here. Figure 12 also shows the “trade-off curve�. This is defined as the set of non-dominated options. Option B is said to be dominated by option A if option A is better than B in both attributes. Thus, in Figure 12, DSM dominates the baseline – and because it is better in both attributes, a rational decision-maker would never prefer the baseline over DSM. Intuitively, one may say that options that lie on this trade-off curve are “closest� to the origin; but they all require trade-offs. Sri Lanka: Environmental Issues in the Power Sector 9 ECA, RMA and ERM Introduction If, as in this illustrative example, there is a sharp corner in the trade-off curve (the so called “knee set�) the option that occupies that corner (or one that may be closest to it) would receive special attention. In this example, “no pollution controls� has much greater emissions than DSM, but only a very small cost advantage. Hence, a decision maker would have to give enormous weight to cost, and almost no weight at all to emissions, to choose this option. Similarly, “renewable energy� (as drawn here in this illustration) has only slightly lower emissions, but very much higher cost than DSM. Again, to prefer renewable energy over DSM would require huge weight be given to emissions, and very small weight to cost. Not all trade-off plots have such knee sets, or even any win-win options, in which case decisions are more difficult to make. Sri Lanka: Environmental Issues in the Power Sector 10 ECA, RMA and ERM The Sri Lanka Power Sector 2 The Sri Lanka Power Sector 2.1 Review of the past two decades The period from 1990 to 2008 has seen significant changes in Sri Lanka’s power sector. The period can be summarised in the following terms: rapid growth in demand electricity sales of 7.2% per year, a move from a system dominated by hydro in 1990 (94%) to a mixed hydro- thermal system by 2008 (42% hydro generation), introduction of policies to allow independent power producers in the 1990s, periods of severe capacity shortages in the period 1996-97 and again in 2000-02 which led to rolling blackouts extending up to eight hours a day, severe delays in obtaining approvals for power plants that had been identified by CEB as least-cost, leading to a proliferation of unplanned, small, environmentally unfriendly, oil-fired power plants, but that could be developed quickly, developed by independent power producers, the proliferation of oil-fired power plants led to a substantial increase in generation costs which, in turn, led electricity prices in Sri Lanka to be among the highest in the region18 for all but smaller residential users, second only to Singapore, the Energy Policy and Strategies of Sri Lanka was approved in 2006 and specified that non-conventional renewable energy (NCRE) should provide at least 10% of the national grid’s energy by the year 2015 and to implement this policy, favourable feed-in tariffs were introduced – by August 2009 some 172 MW of capacity had been commissioned and 4.4% of total grid generated was provided by NCRE in 2008, Sri Lanka’s first coal-fired power plant, with a capacity of 600 MW, developed by CEB on the north-west coast at Norochcholai, Puttalam, is expected to be commissioned at the end of 2010, a second coal-fired power plant is under development at Trincomalee with a capacity of 500 MW (a coal-fired power plant at Trincomalee had been identified in CEB’s least-cost expansion plan as early as 1990 but was abandoned following civil unrest in the Tamil dominated region, an Electricity Reform Act was first proposed in 2002 but its implementation was much delayed and finally an amended version came into force in 2009 18 January 2009. See Table 47 in Annex A1. Sri Lanka: Environmental Issues in the Power Sector 11 ECA, RMA and ERM The Sri Lanka Power Sector giving the Public Utilities Commission of Sri Lanka powers in relation to electricity tariffs, the Electricity Reform Act imposes limitations on private sector investment in power by requiring a shareholding by the government or a government entity in future generation projects, restricting transmission license to be issued only to CEB, and does not allow a majority shareholding by the private sector in a distribution company. A detailed review and assessment of the power sector in Sri Lanka over the past two decades is provided in Annex A1. 2.2 The present vision (business as usual) CEB prepares and publishes a least-cost long-term generation expansion plan (LTGEP) every year. This is done to uphold CEB’s statutory duty to develop and maintain an efficient, coordinated and economical system of electricity supply to satisfy demand. This study selects economically optimal plant additions from given thermal and hydropower generation expansion candidates to forecast demand over a fifteen year time horizon in the light of expected existing and committed power plants, expected reliability level, and environmental factors. As such, the LTGEP represents CEB’s present vision of the power system. Although the most current plan covers 2008 to 2022, a revision of the study less than one year into the planning period was conducted following changes to the local and international social and economic environment not foreseen at the time of the original study. Key deviations from the original assumptions included lower than expected electricity energy demand due to the global economic downturn; marked deviations in international fuel prices; and the changes to the implementation schedule of committed generation plant based on current information. The updated LTGEP is summarised in Table 2 and includes the addition of 3,575 MW of capacity to the system between 2009 and 2022, a reduction of approximately 1,800 MW from the previous year’s Plan. Of this new plant, 705 MW is already committed. The vast majority – 3,155 MW of 3575 MW, or 88%, is expected to consist of coal-fired plant with 300 MW required in all years from 2015, excluding 2016 and 2019. Table 2 Generation expansion plan 2008 - capacity additions Peak Capacity additions Year demand LOLP (%) CCY Coal Hydro Total (MW) 2009 2058 *180 180 0.400 2010 2241 *90+ 90 1.284 2011 2367 **285+ 285 0.352 2012 2524 ***150+ 150 0.507 2013 2681 820 820 0.000 Sri Lanka: Environmental Issues in the Power Sector 12 ECA, RMA and ERM The Sri Lanka Power Sector Peak Capacity additions Year demand LOLP (%) CCY Coal Hydro Total (MW) 2014 2860 250 205 0.000 2015 3031 300 300 0.001 2016 3222 0.014 2017 3423 300 300 0.007 2018 3645 300 300 0.018 2019 3881 0.140 2020 4133 300 300 0.118 2021 4401 300 300 0.114 2022 4686 300 300 0.125 Total 270 3155 150 3575 Table 3 lists the plant scheduled to enter service in each year, along with plant assumed to be retiring. The present-value cost of these additions, known and unknown, up to 2020 is expected to be $ 7.5 billion (LKR 810 billion). Table 3 Additions and retirements in the Long-Term Generation Expansion Plan Year Hydro Thermal additions Thermal retirements additions 2009 2 x 90 MW GT part West Coast - - CCY (already completed) 2010 1 x 270 MW West Coast CCY 2 x 90 MW GT part West Coast - CCY 2011 1 x 285 MW Puttalam Coal (Stage 5 x 17 MW Gas Turbine, - I) Kelanitissa 2012 150 MW - 20 MW ACE Power Matara Upper Kotmale 2013 (2 x 285 MW) Puttalam Coal 22.5 MW Lakdanavi (Stage 2 & 3) - 4 X 18 MW Sapugaskanda Diesel 1 x 250 MW Trincomalee Coal 20 MW ACE Power Horana (Stage 1) 2014 - 1 x 250 MW Trincomalee Coal - (Stage 2) 2015 - 1 x 300 MW Coal Plant 60 MW Colombo Power 100 MW Heladanavi Diesel, Puttalam 100 MW ACE Power Diesel, Embilipitiya Sri Lanka: Environmental Issues in the Power Sector 13 ECA, RMA and ERM The Sri Lanka Power Sector Year Hydro Thermal additions Thermal retirements additions 2016 - - - 2017 - 1 x 300 MW Coal Plant - 2018 - 1 x 300 MW Coal Plant 49 MW Asia Power 115 MW Gas Turbine, Kelanitissa 2019 - - - 2020 - 1 x 300 MW Coal Plant - 2021 - 1 x 300 MW Coal Plant - 2022 - 1 x 300 MW Coal Plant - Notes: Committed plants are shown in italics. Sri Lanka: Environmental Issues in the Power Sector 14 ECA, RMA and ERM Assumptions 3 Assumptions 3.1 Macroeconomic assumptions Over the past five years, economic growth in Sri Lanka has been strong, with rates not falling below five percent in any years since 2003. Like most nations, however, Sri Lanka’s economy has not gone untouched by the economic turmoil which hit the world in the latter part of 2008. In the first nine months of 2008, GDP grew at a rate of 6.5%, falling to 4.3% in the last quarter and to 1.5% in the first quarter of 2009. Yet, positive signs for the economy in the near-term exist. The most important of these is the ending of a three decades long conflict, the result of which will mean greater integration of the Northern and Eastern Provinces with the rest of the country. Economically, the conclusion of the conflict brings with it reconstruction, expansion of markets and better utilisation of natural and human resources. This domestic boost will be accompanied by increased foreign confidence, which is expected to bring with it increased foreign investment and assistance from both the private sector and Sri Lanka’s development partners. Optimism given the end of the conflict led the Sri Lankan Central Bank to revise, in July of 2009, its 2009 growth forecast of 2.5%, announced in March of 2009, to 3.5% to 4.5%. In addition, Sri Lanka’s economy is expected to benefit from a stringent monetary policy followed in 2007 and 2008. Restricting monetary expansion through quantitative targeting, the policy was required given the historically high levels of inflation weakening the economy. The policy had its intended effect, with Sri Lanka recording its sharpest ever deceleration of year-on-year inflation between June 2008 and February of 2009: 28.2% to 7.6%, respectively. Inflation is forecast to remain in the single digits throughout 2009 and to stabilise at a low level in the medium-term. With inflation at relatively low levels, the increase in disposable income, combined with the conclusion of the war, is expected to provide Sri Lanka with a domestic source of demand at a time when global demand is limited. Further economic stimulus is expected to come from a delayed International Monetary Fund loan as well as a stimulus package announced by the GoSL and easing of monetary policy. As mentioned, this has led the Central Bank to forecast positive economic growth, albeit at a somewhat depressed level relative to prior years, for 2009. In the medium- term, global economic recovery along with increased intra-regional Asian trade and tourism is expected to return growth levels to their pre-2009 levels. Growth during this period will also be supported through the planned rehabilitation and resettlement projects planned for the North and the East. As shown in Table 4, en toto, this has led the Central Bank to forecast GDP growth of 5.0%, 6.0% and 6.5% in 2010, 2011 and 2012, respectively. Sri Lanka: Environmental Issues in the Power Sector 15 ECA, RMA and ERM Assumptions Table 4 Central Bank GDP Forecast 2009 2010 2011 2012 Real GDP Growth 2.5% 5.0% 6.0% 6.5% 3.2 Various assumptions The WASP IV model was used to analyse the present valued capital, fuel and operating costs of the Sri Lankan electricity system over the selected planning period. The model normally selects the least-cost investment plan from among all of the investment sequences available to it based on minimising the present-valued costs both in terms of optimal dispatch of power plants within each period and the minimum cost over the whole planning horizon. The user may, however, intervene to require the model to optimise subject to certain constraints – such as a requirement that specific plants should be commissioned irrespective of their costs. The approaches used in the analysis relating to certain cost and performance parameters are outlined below. Planning horizon. The analysis is conducted over a twenty year period from 2009 to 2028. To account for differences in the residual lives of plants in the year 2028, the salvage value19 of each plant is estimated by the model at that date, then present valued back to the start of the planning horizon, and finally subtracted from the present-valued costs. The treatment of interest during construction (IDC). The software used to estimate system costs (WASP IV) is given a single capital cost which is assumed to occur at the time of commissioning. To allow for the construction period and the outlay of expenditures during the construction period, the future value of the stream of disbursements at the assumed discount rate is estimated and used. For example, in the case of CCGT with a three year construction period, the value entered into the model is 13.54% higher than the simple cumulative capital cost. Capacity. Actual output of plants at time of peak demand may be less than the nameplate capacity because of the higher ambient temperature at the time of system peak which lowers the MW output that can be achieved and because the power available will be dependant upon auxiliaries needed by the plant. For these (and other reasons, discussed elsewhere), the analysis uses output at time of system peak, net of auxiliary consumption. Capital costs, and heat rates and efficiency, are also given on a net basis20. LHV and HHV of fuels. The gross basis (HHV) is used by CEB and is also used in the current analysis. 19 The present value at the end of the planning horizon of the residual annualised capital cost stream. 20 This differs from CEB’s current practice. Sri Lanka: Environmental Issues in the Power Sector 16 ECA, RMA and ERM Assumptions The reasons for using these approaches are explained more fully in Annex A2 3.3 Fuel prices assumed in the analysis The basis for the assumptions for fuel prices that are used in the analysis are provided in Annex A5 and summarised in Table 5. Table 5 EIPS fuel price assumptions LNG, cif Coal Residual Coal (excl. Diesel Fuel Oil Naphtha (non- Oil (Trinco) terminal Trinco) charges)(2) USD/bbl USD/bbl USD/bbl USD/bbl USD/mt USD/mt USD/mbtu EIPS Assumptions Crude Price = 94.2 63.4 57.1 84.8 111.7 102.7 9.5 75 USD/bbl(1) Crude Price = 159.7 107.7 96.9 143.7 170.0 161.0 16.1 125 USD/bbl(1) CEB Assumptions CEB 2008 Study 85.2 63.4 79.1 NA NA (Crude Oil = 67 USD/bbl) CEB Addendum(3) 127.0 84.9 76.7 97 147.5 NA NA (Crude Oil = 101 USD/bbl) Notes: (1) In 2009 prices, 75 USD/bbl = 76.7 USD/bbl and 125 USD/bbl = 127.9 USD/bbl. This is based on the same inflation assumption of 2.3% as in the IEA 2008 World Energy Outlook. (2) Including assumed freight from Qatar and the variable costs of regasification, but excluding the terminal costs (whose capital costs and fixed O&M are built into the capital cost of the 1st power block). See detailed discussion of LNG costs in Section A5.1.4 (3) Prices based on December 2007-November 2008 (see CEB Expansion Plan, Table Ad.4). The derivation of the coal price assumptions are as summarised in Table 6. Sri Lanka: Environmental Issues in the Power Sector 17 ECA, RMA and ERM Assumptions Table 6 Derivation of coal prices Crude Oil Price 75 USD/bbl 125 USD/bbl Coal, fob Newcastle(1) USD/tonne 88.7 147.0 + Capesize to Trinco(2) USD/tonne 14.0 14.0 Coal, cif Trincomalee USD/tonne 102.7 161.0 + nonTrinco Penalty(3) USD/tonne 9.0 9.0 Coal, cif non-Trincomalee USD/tonne 111.7 170.0 Notes: (1) Based on World Bank forecast of relative coal prices. (2) Assumes cape size vessels $12/tonne + 2$/tonne unloading/handling. (3) Assumes Panamax vessels $20/tonne and +$5/tonne barge transhipment to jetty. Finally, Figure 13 shows the scenario assumptions in the context of the historical relationship between oil and coal prices, and the IEA and World Bank forecasts. Also shown are the fuel price assumptions in the 2009-2022 CEB expansion plan: the original 2008 plan assumed a crude oil price of 66.7 $/bbl; the addendum assumed $101/bbl. Both sets of CEB fuel price assumptions fall in the general pattern of World Bank forecasts and the historical trend line.21 Figure 13 Scenario assumptions Notes: Crudeoil =average of Brent,WTI and Dubai, historical prices at actual; all forecasts at constant 2007-2008 prices It should be noted that the purpose of this exercise is not to provide “better� forecasts, but to examine the robustness of the policy scenarios to a range of consistent oil/coal/LNG price forecasts. The high oil price scenario proposed for this study, at $125/bbl (at 2008 prices), is reached in the IEA forecast only in 2030: however, this oil 21 However, the CEB coal forecast includes freight, the amount of which is not noted in the report. Sri Lanka: Environmental Issues in the Power Sector 18 ECA, RMA and ERM Assumptions price will give an indication of the penetration of renewables if the expansion of new oil supplies does not keep pace with the expected demand growth once the world emerges from its current recession. 3.4 Carbon accounting There are two issues in carbon accounting of importance to the present study. The first relates to GHG emissions from hydro reservoirs (relevant to the hydro and renewable energy scenarios). The second is whether to consider just the GHG emissions from combustion (which are straightforward), or whether to include emissions from the entire life-cycle of the power plant and fuels including the extraction and processing of the fuels. Each of these issues is discussed in Annex A3. As all of the Sri Lanka hydro candidates have significantly higher power densities (above 29 W/m2) than the lower bound for CDM projects eligible without penalty (i.e., greater than 10 W/m2, whereas projects with power densities between 4 and 10 W/m2 have a penalty of 90kgCO2 /MWh) we may ignore methane and CO2 fluxes from the Sri Lanka projects. CO2 emissions in this study are calculated both with and without life-cycle adjustments. The assumptions used are as follows: The net CO2 emissions from the reservoirs of the candidate projects can be ignored (based on the draft guideline for the CDM eligibility of hydro projects). The life cycle emissions associated with materials and construction of hydro projects are taken as 15gCO2/kWh. The calculations of emissions from coal and natural gas combustion use the IPCC default values for the fuel concerned. The life cycle emissions for coal plants are taken as 10% higher than the combustion impacts. For imported LNG, life cycle emissions are taken as 40% higher than the combustion impacts. 3.5 Demand Forecasts As part of this study, a forecast of demand was prepared, the results of which are summarised here, while a more comprehensive discussion is given in Annex A4. To develop this forecast, an initial review was made of the approach undertaken by the Ceylon Electricity Board (CEB). Normally, electricity demand projections prepared by CEB are based on econometric analysis of electricity sales by sector against independent variables such as GDP, population and electricity price. In some cases dynamic relationships are incorporated into the forecasting equations. The structure of the equations, the included parameters and the coefficients used in the equations Sri Lanka: Environmental Issues in the Power Sector 19 ECA, RMA and ERM Assumptions change from year to year depending on the latest data and the results of the regression analysis. CEB’s approach for each forecast is to update the database and with the new data to identify the relationship between demand and independent variables that gives the best statistical fit. Unfortunately, CEB’s forecasting model recently failed to predict the degree to which electricity demand growth fell in response to the economic downturn in the second half of 2008. While GNP continued to increase at 5% to 6% per year in 2008, electricity demand growth dropped to only 1.4% (at the time of the CEB forecast the estimate was that demand growth would be between 3% and 6% but the outturn was lower still). For the purposes of the latest generation investment plan, CEB therefore temporarily adopted a time trend approach and made an ad hoc adjustment to the forecast for 2009, assuming a growth rate of 4.6%. Thereafter, demand is expected to grow at its historic rate of 6.7% per annum. In developing the forecast for this study, a more widely used practice, and one not used by the CEB, of assuming a log-linear relationship between the electricity demand and the independent variables was adopted. Demand for electricity is assumed to be based on GDP, prices, income elasticity and price elasticity, with the latter two determined from econometric analysis. The results of this econometric analysis show that, for domestic demand, the response to changes in GDP and price do not all occur within the year. Specifically, the long-term elasticities are 1.57 for GDP and -0.073 for price22; i.e., for every one percent increase in GDP, GWh sales increase by 1.57% and for every one percent increase in price, GWh sales will fall by 0.073%. This suggests a relatively weak impact of price on sales. For industrial and general demand, the changes in GDP and the price impact on GWh sales occur within the same year so that, for every one percent increase in GDP, GWh sales will increase by 1.3098% and for every one percent increase in price, GWh sales will fall by 0.021%. No elasticity for the customer category “other� (street lighting and religious buildings) was estimated as a time trend approach is more appropriate. Thus, sales in this category are assumed to grow at the historical rate of 5.8% per year. For GDP, projections of GDP up to the year 2012 were obtained from the Central Bank of Sri Lanka with growth rates of 2.5%, 5.0%, 6.0% and 6.5% in 2009 to 2012 respectively. Beyond 2012 we assume that GDP growth will be 6% per year for five years (2013-17), 5% per year for the next five years (2018-22), and 4.5% per year thereafter. The forecast for losses includes 1% for auxiliary consumption in power plants and an overall target level of 14% expected to be achieved by 2017 (from 15.7% today). The forecast for the load factor is based on an extrapolation of past load factors (excluding years with load shedding). The resultant forecast of demand for the three customer classes along with actual demand in 2007 and 2008 is displayed in Figure 14 for select years. By 2030, demand for electricity is expected to be nearly five times its current level of 8,348 GWh, or 40,638 GWh. Of this level, demand by domestic customers is expected to rise from 3,230 GWh to 19,860 GWh; demand by I&G customers is expected to rise from 4,936 22 This is calculated by dividing the short-term coefficient or elasticity by (1 – coefficient on the lagged dependent variable). Sri Lanka: Environmental Issues in the Power Sector 20 ECA, RMA and ERM Assumptions GWh to 20,148 GWh; and, for other customers, demand is expected to rise from 182 GWh to 692 GWh. The impacts of demand-side management (DSM) measures on realised demand are analysed in a DSM case described in Section 5.10. Figure 14 Electricity Demand 45,000 40,000 35,000 30,000 25,000 GWh 20,000 15,000 10,000 5,000 0 2007 2008 2009 2010 2015 2020 2025 2030 Other 186 182 193 204 270 358 475 629 I&G 4,824 4,936 5,098 5,431 7,977 11,225 15,132 20,148 Domestic 3,219 3,230 3,597 3,946 6,298 9,671 14,018 19,860 Sri Lanka: Environmental Issues in the Power Sector 21 ECA, RMA and ERM Environmental regulations and standards 4 Environmental regulations and standards Electricity generation in Sri Lanka was traditionally provided from hydropower but since the 1990s, oil-fired power plants have taken a significant share of generation and in future electricity will be supplied primarily from power plants burning fossil-fuels. Hydropower will continue to be developed in Sri Lanka. GoSL does have plans to continue developing its hydropower potential, although the majority of this will be through smaller projects. As the power sector transitions from hydropower to power plants burning fossil-fuels, so too the dominant environmental issues have shifted from concerns over the relocation of people displaced by reservoirs, to concerns over air quality and waste. Population displacement may also arise with the building of non-hydro generation, particularly given the country’s high and growing population density23 - Sri Lanka has one of the highest population densities in Asia and is ranked 45 out of 238 countries with regard to population density. But the main concern focuses on air quality and waste. The country has little experience in managing issues relating to emissions from coal- fired power plants. Fortunately, a host of industrial pollution standards and regulations, although not specifically aimed at the power sector, will govern their management. In Section 4 below, we consider environmental regulations and standards aimed at coal-fired and other fossil-fuelled power plants for the primary purpose of protecting the quality of air. We also discuss the estimates of the costs of the environmental damage caused by residual emissions that cannot be entirely prevented through environmental regulations. 4.1 Consequences of emissions In many parts of the world, pressure to reduce emissions from coal fired power stations has been exerted in response to damage resulting from long range transport of pollution, sometimes on ecosystems. This is certainly true of North America and northern Europe, where problems of acid and nutrient nitrogen have been identified. There is also an issue relating to the contribution of the power sector to regional concentrations of fine particles and ozone, both associated with human health effects. Concentrations of ozone might be expected to increase significantly in this region in the future, in response to increased emissions and climate change. Susceptibility to acid deposition is largely a function of soil type. Within Asia, it is southern China and South East Asia where soils are most vulnerable to acid deposition (see Figure 15 and Figure 16 below). Most of India is insensitive, although some coastal areas of south west India appear to be slightly vulnerable. Sri Lanka is mostly 23For example, the building of the Puttalam coal-fired power plant resulted in the displacement and resettlement of 80 families. Sri Lanka: Environmental Issues in the Power Sector 22 ECA, RMA and ERM Environmental regulations and standards insensitive, although some areas of sensitivity undoubtedly occur and these are likely to be in the west of the country. The subject has not been studied extensively and any definitive conclusions cannot be drawn at this stage. As emissions across Asia continue to rise, it could be that ecosystems will begin to show signs of stress in the future. Figure 15 Global soil sensitivity to acidic deposition Source: Kuylenstierna, J. C. I., H. Rodhe, S. Cinderby, and K. Hicks. (2001) Acidification in developing countries: ecosystem sensitivity and the critical load approach on a global scale. Ambio 30:20–28. Figure 16 Soil sensitivity to future acid deposition in Asia Source: W. Kevin Hicks, Johan C. I. Kuylenstierna, Anne Owen, Frank Dentener, Hans-Martin Seip, and Henning Rodhe (2008) Soil Sensitivity to Acidification in Asia: Status and Prospects AMBIO: A Journal of the Human Environment 37(4):295-303. Sri Lanka: Environmental Issues in the Power Sector 23 ECA, RMA and ERM Environmental regulations and standards Beyond issues of air quality and waste disposal in Sri Lanka are concerns over the loss of forest cover, biodiversity and the degradation coastal zones. Although power sector development has contributed little to Sri Lanka’s deforestation, rapid loss of the forest has meant that any additional loss is highly scrutinised. The FAO estimates that 35% of Sri Lanka’s forest cover was lost between 1990 and 2005, with current loss averaging just over 2% per annum. Hence, any potential loss resulting from new build power plants is likely to be contentious, despite being small relative to the amount lost through planned agricultural development, chena cultivation, encroachment by unplanned settlement and uncontrolled fuelwood and timber extraction. A similar situation exists in terms of biodiversity. With 23% of flowering plant and 16% of mammals endemic to the island, Sri Lanka has the highest level of biological diversity among Asian countries. However, the nation is also rapidly losing this biodiversity and thus any project which threatens it further will come under intense scrutiny, including those of the power sector. Furthermore, given the pressure on land, new power sector developments are likely to be forced into coastal areas, which are not only fragile, but upon which tourism relies. 4.2 Principles 4.2.1 Considerations in setting emission standards Limits on releases from any industrial process, including power generation, are intended to control pollution and to minimise or to eliminate harm to the environment – but there are a number of alternative means to achieve this aim, each with their strengths and weaknesses. The process of establishing emission standards can be examined in by considering the sequence that starts with the fuel and ends with the environment: Each part of this sequence provides an opportunity for imposing controls. Starting on the left, the electricity generating process is dependent on the fuel input, with its inherent pollutant content, notably of sulphur. The generating process itself can present an opportunity for regulation through the specification of the design. The point of release (i.e., a chimney stack) is a commonly used point at which to exert a limit through defined emission standards. Finally, the release has some impact on the environment or on a “receptor� and environmental quality standards (eg., concentrations of pollutants in the air) can be used to define maximum releases of pollutants at any given plant to achieve that quality standard. The amount of any pollutant may be controlled by specification on the fuel or by dictating the technology to be used, in the case of a new power station. Low NOx combustion techniques and FGD are obvious examples of this. Sri Lanka: Environmental Issues in the Power Sector 24 ECA, RMA and ERM Environmental regulations and standards The form of any standard applied to the emission of a pollutant at the point of release will have to be specified. There are a number of considerations here, such as: over what time period will any measurement take place? should it be expressed as a concentration in the flue gas, or as an annual mass allowance? if the standard is a concentration, is it absolute, or are occasional excursions permitted? The requirements of monitoring, compliance and enforcement of any emission standard may also be factors in dictating the form of any standard adopted. A standard that cannot be sensibly measured or complied with is not a good standard. Finally, the impact on the environment cannot be ignored. Ultimately, the function of regulating emissions is to prevent unacceptable harm to the environment and, on a site specific basis, the emissions must be constrained to a level that ensures that impacts are not significant. 4.2.2 Achievable emissions versus avoidance of harm There are, essentially, two approaches to determining a maximum quantity of pollutant that may be released from a power station, or any industrial process. The first is to set a limit based on what is achievable, using the best technology available. This is, to a large extent, the approach adopted in North America and in the European Union, noting that in each case there is an economic component to the determination of what constitutes the ‘availability’ of the ‘best’ technology. This approach is not, strictly speaking, governed by considerations of harm to the environment, but what can be achieved by the application of technology at any given time. It may be that regulating emissions in this way goes beyond what is necessary to protect the environment, or, conversely, it may be insufficient. In the case of emissions from a power station, it can be argued with some justification that there is always an environmental benefit to be gained from reducing emissions. Human health, at the population level, appears to be affected by air pollution at all non-zero ambient concentrations, i.e., compliance with air quality standards does not eliminate health effects, as demonstrated by a wealth of epidemiological studies around the world. Some ecosystems are affected by very small quantities of air pollution. Thus, driving down emissions to the lowest practical level has a strong attraction for environmental protection reasons. Another subtlety is that environmental progress around the world has largely been achieved by regulatory pressure on emissions that then drives the development of technologies to meet the emission limits. Without such pressure, there is no incentive to improve the control technology. The alternative approach is to determine the amount of pollution released that causes harm in the environment, eg., by reference to air quality standards, and work back from there to calculate the maximum permissible emission. This could be expressed either as an annual mass release, or as a short term average, depending on the nature Sri Lanka: Environmental Issues in the Power Sector 25 ECA, RMA and ERM Environmental regulations and standards of the environmental harm considered. If the annual average ambient pollutant concentration is the measure of harm selected, then it is the long term average release that should be regulated. If, on the other hand, it is the short term average concentration of a pollutant close to the power plant that is critical, then it is the release of pollutants over short periods of time that must be regulated. In practice, a combination of these two approaches is desirable. The technological abatement solutions should be applied if available and these set a benchmark for the maximum emission. If this approach is sufficient to protect the environment, eg., for air quality, then the emission standards equate to the benchmark emissions that the technology achieves. If not, then there is a case for more stringent limits and the technology will have to be enhanced (at greater cost) to prevent the observed or predicted environmental damage. 4.2.3 The Sri Lankan situation Air pollution in Sri Lanka is a recognised environmental problem, with highest concentrations in the urban areas, where road transport is a major contributor to local airborne concentrations. Despite the increase in oil-fired power generation located in Colombo, existing power stations in Sri Lanka do not contribute significantly to local air quality problems. Figure 17 shows trends in SO2 concentrations in Colombo between 1997 and 2006 and indicates an improvement after the year 2000. Figure 17 Trends in SO2 levels in Colombo Clean Air in Sri Lanka: Summary of progress on improving air quality, November 2008. Taking all the air pollution issues into account, it seems most likely that the most critical issue for the regulation of power station emissions will be local air quality and the air quality standard most at risk of being not complied with is the one hour average for SO2. This would argue for an emission standard set as a concentration (in mg Nm-3) measured and averaged over a short period, such as an hour or a day rather than as an annual mass limit (in tonnes). Sri Lanka: Environmental Issues in the Power Sector 26 ECA, RMA and ERM Environmental regulations and standards 4.3 The current environmental regulatory framework The primary piece of legislation for environmental management and protection is the 1980 National Environmental Act (NEA) No. 47, and its subsequent amendments. Enacted to protect and manage the environment as a whole, the original provisions were focused on environmental management and included the establishment of the Central Environmental Authority (CEA). Officially launched in 1981, CEA was essentially a coordination and policy-making body with little enforcement power. The National Environment (Amendment) Acts No. 56 of 1988 and No. 53 of 2000 changed this, granting the CEA wider regulatory powers and included the mandate to implement two main regulatory instruments: Environmental Protection License (EPL) (for all industries), Environmental Impact Assessment (EIA) (for major development projects, including power). The regulations governing EPLs were issued in February 1990 and, for EIAs, in June 1993. While the latter encompasses what one would expect – a procedure that identifies all major environmental impacts of the project and mitigation actions undertaken to limit these impacts – the former stipulates the standards and criteria under which a project may discharge or deposit effluents or emissions into the environment. Although the issuing of licences was originally administered by the CEA, the process for some low polluting industries (not including the power sector) has been delegated to the provinces, part of an increasing trend of devolution of the powers of environmental management and protection. With regard to the role of these regulations on the power sector, the NEA requires environmental clearances for power plants to be obtained either from CEA or from a Project Approving Agency (PAA) authorised by the NEA. The Ministry of Power and Energy (MPE) is usually the designated PAA for power sector approvals and has established an environment cell in its planning division to implement the requirements of NEA. There are two classifications of plants specified in the environmental regulatory regime: Thermal power plants (new or capacity additions to existing plants) exceeding 25 MW, and Hydro power plants exceeding 50 MW. Initial Environmental Examinations (IEEs) rather than full EIAs are required for some projects. In addition to the above legislation, Sri Lanka has developed several environmental standards which are enforced by the CEA through the EPL Procedure and EIA process. Those of major importance to the power sector include national ambient air quality standards, industrial effluent standards and the yet to be ratified air emissions standards for air polluting industries (i.e., source specific standards). Solid waste from Sri Lanka: Environmental Issues in the Power Sector 27 ECA, RMA and ERM Environmental regulations and standards power plants in Sri Lanka is governed by the National Environmental (Protection and Quality) Regulation No. 01 of 1990 amended by Regulation 924/13 in April 1996. 4.4 Air quality standards Ambient air quality is governed by the National Environmental (Ambient AQ) Standards. First established in 1994, National Environmental Regulations (No. 850/4) were amended in August 2008 (No. 1562/22) as shown in Table 7. For comparison, the World Health Organization (WHO) guidelines are also shown; it should be noted that these are guidelines and have no statutory role. Perhaps for this reason they tend to be more stringent than many national air quality standards around the world. This is particularly true for particulate matter and SO2. The Sri Lankan standards should not be regarded as being lax through comparison with the WHO guidelines and the one hour average concentration of 200 µg m-3 as a standard for SO2 represents a significant regulatory constraint for an unabated coal fired power station. Table 7 National ambient air quality standards Pollutant Averaging time Maximum permissible concentration Sri Lanka WHO24 guidelines µg/m3 ppm µg/m3 ppm PM10 Annual 50 - 20 - 24 hours 100 - 50 - PM2.5 Annual 25 - 10 - 24 hours 50 - 25 - NO2 Annual - - 40 0.021 24 hours 100 0.05 - - 8 hours 150 0.08 - - 1 hour 250 0.13 200 0.106 SO2 24 hours 80 0.03 20 0.007 8 hours 120 0.05 - - 1 hour 200 0.08 - - 10 minutes - - 500 0.175 24 World Health Organisation. Sri Lanka: Environmental Issues in the Power Sector 28 ECA, RMA and ERM Environmental regulations and standards Pollutant Averaging time Maximum permissible concentration Sri Lanka WHO24 guidelines µg/m3 ppm µg/m3 ppm O3 1 hour 200 0.10 - - 8 hours - - 100 0.05 CO 8 hours 10,000 9.00 10,000 10 1 hour 30,000 26.00 30,000 25 30 minutes - - 60,000 50 Anytime 58,000 50.00 4.5 Proposed stack emission regulations Although ambient air quality and industrial effluent standards are enshrined in law, standards for source-specific atmospheric emissions are in draft form only and are thus presently used as a guideline when making investment about emissions reduction technology. Once formally issued by CEA, these will apply to new industries with immediate effect while existing industrial operations will be given a grace period to come into compliance. To inform the final limits, a comprehensive study is presently under way and includes a survey of the existing sources as well as a road map for full implementation of a revised set of standards from stationery sources. The latest draft recommendations for large power plants are shown in Table 8. Table 8 Proposed stack emission standards for larger plants Fuel Size (MWe) Pollutants Maximum emission level Oil ≥ 100 SOx 850 mg/Nm3 NOx 450 mg/Nm3 PM 150 mg/Nm3 Coal ≥ 50 SOx 800 mg/Nm3 NOx 650 mg/Nm3 PM 100 mg/Nm3 Smoke 10% opacity Natural gas ≥ 50 SOx 75 mg/Nm3 NOx 300 mg/Nm3 PM 75 mg/Nm3 Sri Lanka: Environmental Issues in the Power Sector 29 ECA, RMA and ERM Environmental regulations and standards 4.6 Regulation of Puttalam coal-fired power plant Although environmental management is mainly done at a national level through CEA, as mentioned above, devolution is underway. This is currently the case in North Western Provincial Council, which assumed jurisdiction of environmental management through the North Western Province Environmental Statute No. 12 of 1990. As a result of this statute, the NEA is no longer a national act. This outcome is important in that a good proportion of heavy industry is located in the province, not to mention the first coal plant to be built. Also of influence over the power sector is the Waste Management Authority Statute No. 09 of 1999 of the Western Province. To examine the potential influence of these statutes on the power sector, particularly coal-fired generation, consider the Puttalam coal-fired power plant. As mentioned above, this plant is located in the North Western Province and thus subject to its statutes with regard to environmental management. Currently under construction and expected to begin operation in late 2010, Puttalam received its first Certificate of Environmental Clearance (CEC) from the North Western Provincial Environmental Authority in January 1999. The project was subsequently put on hold until 2005. The CEC was revalidated by the same Provincial authority in February 2006. The first CEC required that the power plant should burn low ash coal with a sulphur content of less than 0.65% but did not require the use of FGD. CEB discovered, however, that the use of low sulphur coal would severely restrict the options for sourcing coal and decided therefore to adopt FGD and to use higher sulphur coal (resulting in lower overall sulphur emissions even though higher sulphur coal will be used). The revalidated CEC approved the use of FGD but, anomalously, did not modify the requirement to use low sulphur coal. CEA required the use of a stack height such that ambient air quality standards shown in Table 9 would be met. These are consistent with the standards currently proposed for Sri Lanka and described above. Table 9 Puttalam coal-fired plant – ambient air quality standards Pollutant Averaging time Maximum ppm permissible limit (mg/m3) TSP 24 hour average 0.30 NO2 1 hour average 0.25 0.08 SO2 1 hour average 0.20 0.08 The CEC also required that the plant maintain emission standards of: TSP 40 mg/MJ Opacity 20% SO2 520 mg/MJ NOx 300 mg/MJ Sri Lanka: Environmental Issues in the Power Sector 30 ECA, RMA and ERM Environmental regulations and standards CEB expects that the fly ash waste from the power plant will be utilised by a cement plant 20 km from the plant. The plant is required by its CEC to burn coal with low ash and the ash produced by the plant is understood to have a carbon content of less that 0.35% which is particularly suitable for construction material. 4.7 Implications of emission standards for use of FGD Below we consider the implications of the current and proposed stack emission standards for coal-fired power plant developers and whether they would, in effect, be required to fit FGD to meet those standards. We begin by considering the price difference between low sulphur and high sulphur coal. 4.7.1 Premium on low sulphur and ultra-low sulphur coal The current emission standards are set such that a new coal power plant such as Puttalam would need, in the absence of FGD, to burn coal with a sulphur content of no more than 0.7% by weight. International sources of low sulphur coal, however, are limited primarily to Indonesia and, to a much lesser extent, Russia and South America. This limited availability reduces options for competitive sourcing, thereby raising the price or risking that the price will be raised. Thus, meeting the current environmental standard through the use of low-sulphur coal alone will come at a cost. Yet the magnitude of this cost is difficult to determine. A review of pricing data from the US suggests that the premium for low sulphur coal with a sulphur content of 0.8% is currently 13 $/tonne compared with 3% sulphur coal, while 0.8% sulphur coal has a premium of 4.5 $/tonne over coal with 3% sulphur. However, the regulatory environment and other drivers affecting this premium are specific to the US and there would be a wide degree of uncertainty in extrapolating this information to the international coal markets. We note that the extra cost of low sulphur coal with a premium of 5 $/tonne in present value terms over a 25 year period would be worth $ 37 million for a 315 MW (nameplate capacity) operating at a 75% load factor. For a premium of 10 $/tonne the present-value additional cost would be $ 74 million. As the demand for low sulphur coal is likely to increase as countries impose increasingly strict emissions standards on SO2, the premium is likely to rise. However, it could also fall if emission standards effectively mandate the use of FGD, thus making low sulphur coal less valuable. One option to offset this cost is to blend Indonesian coal, a good percentage of which has a sulphur content of less than 0.1%, with the more abundant coals with relatively higher sulphur content. Whether this makes economic sense will ultimately depend on the respective prices of the various coal inputs and the effective sulphur content achieved. A more viable alternative may be to fit FGD. Sri Lanka: Environmental Issues in the Power Sector 31 ECA, RMA and ERM Environmental regulations and standards 4.7.2 Purchasing low sulphur coal versus fitting FGD – the cost trade-off As an alternative to paying a premium for low sulphur coal, power plants have the option to fit FGD. The decision, however, may not be immediately obvious given the uncertainty in the fuel premium over the life of the plant. To illustrate, consider such a decision facing a new coal-fired power plant in Sri Lanka. As the cost of fitting FGD in Sri Lanka is not certain (with a sample of only one power plant) a range of costs for FGD in Indonesia are utilised. In Indonesia, the typical capital and operating expenditures for installing FGD are estimated to be in the range of 150 to 250 $/kW for the former and 0.7 to 1.0 mills/kWh for the latter. Given these costs, one can create a trade-off curve representing the decision of whether to fit FGD or pay a premium for low sulphur coal. This curve, which shows, for a range of FGD costs and low sulphur coal premiums, the break-even point between the two lifetime costs, is shown in Figure 18. For example, for a capital cost of 170 $/kW, it is cheaper to fit FGD when the premium on low sulphur coal is greater than just under 9 $/tonne and cheaper to pay the premium when it is less than just under 9 $/tonne. Figure 18 Fitting FGD versus Paying for low sulphur coal 14 13 Low Sulphur Coal Premium, $/tonne Fit FGD (as cheaper than coal premium) 12 mium 11 l Pre r Coa lphu o w Su 10 D/L twe en FG n Be -Eve 9 B reak 8 Purchase Low Sulpur Coal (as cheaper than FGD) 7 6 150 160 170 180 190 200 210 220 230 240 250 Capital Cost of FGD, $/kW From a pure cost perspective, fitting FGD does not make begin to make financial sense until the coal premium rises above 7 $/tonne (based on capital and operating costs going no lower than 150 $/kW and 0.7 mills/kWh, respectively). While current premiums for low sulphur coal may be less than this value (or may be more), their future value, particularly over the life of a power plant, is difficult to predict. For an investor making the decision of whether to invest in FGD, the probability of an increase is almost certainly higher than the probability of either a decrease or, indeed, a constant premium. For this reason alone, an entirely cost-driven decision on the part of investor may lead to the fitting of FGD. However, additional considerations may tip the balance further. Sri Lanka: Environmental Issues in the Power Sector 32 ECA, RMA and ERM Environmental regulations and standards 4.7.3 Diversity of sources of supply of low sulphur coal Even if the environmental standards, either as currently set or as proposed, do not rule out the use of low sulphur coal alone for compliance, fitting of FGD appears likely to be chosen by developers of new coal-fired power stations. The obligation to procure appropriate low sulphur coal for Sri Lanka will narrow the sources of supply and restrict competition – so that the price will not be as competitive as standard quality coal. Moreover, the obligation to purchase low sulphur coal could leave Sri Lanka at risk of fuel supply disruptions or price spikes if one of the limited number of suppliers faces difficulties. Fitting FGD is the safe investment that provides both cost and supply security. Indeed, that this is likely to be the case is evidenced by the decision of Puttalam to fit FGD, despite only being required to meet the current SO2 standard of 1500 mg/Nm3 (520mg/MJ) and a sulphur content of 0.7%. One of the key factors underlying the decision was the wish to keep open the option of obtaining coal from a wider range of sources. 4.7.4 Implications for standard setting Although, as illustrated above, fitting FGD does not begin to make financial sense until the coal premium rises above 7 $/tonne, from a regulatory and environmental standpoint, encouraging or even mandating FGD may make good sense. For example, for a 315 MW (nameplate capacity) conventional coal plant operating at a 75% annual capacity factor, SO2 emissions from burning coal with sulphur content of 3% and with FGD fitted and operating continuously would be 4,989 tonnes per annum. When burning coal with a sulphur content of 0.35% to comply with emission standards of 800 mg/Nm3, but no FGD fitted, SO2 emissions would be 5,820 tonnes per annum, or nearly 20% greater25. The cost difference to the power plant operator of fitting FGD or burning low sulphur coal, is relatively small and may, in any case, favour fitting FGD. By fitting FGD, the operator would comply with very tight emission standards and at the same time would have greater flexibility in sourcing coal. The lower emissions does, however, depend on the way that the FGD is operated and identical level of emissions would arise if the operator, as they are likely to do, complies with the emission standards by operating the FGD at part capacity. Tight standards, possibly even tighter than those currently proposed (800 mg/Nm3) to, say, 400 mg/Nm3, or mandating FGD, would therefore have low cost implications for the power sector but could reduce SO2 emissions, increase the sourcing options allowing more competitive procurement, and it would allow the developers to present a cleaner image to the public. 25 To comply with current standards equivalent to 1500 mg/Nm3 by using coal with sulphur content of 0.7% without FGD, the SO2 emissions would be 11,640 tonnes/year or 130% greater than if FGD were fitted. Sri Lanka: Environmental Issues in the Power Sector 33 ECA, RMA and ERM Environmental regulations and standards 4.8 Environmental damage costs In the ideal case, local environmental damage costs would be monetized, and included as a cost in the benefit cost analysis. Such a monetization is extremely difficult because it requires the quantification of three linkages: translating incremental fossil generation emissions from the stack into increases of ambient air pollution concentrations (requiring air quality models). translating incremental increases in ambient pollution concentrations into rates of morbidity and mortality (requiring epidemiological studies). translating increased mortality and morbidity into economic damage costs (requiring methods of economic valuation of human life). Every one of these steps is complex, and fraught with complications arising from the complexity of the phenomena involved. While simple air quality models are routinely used in environmental assessments to ensure compliance with ambient air quality standards, many of the most damaging pollutants arise during long range atmospheric pollution (such as small sulphate particles formed as oxidation products of SO2). The result is that the source of a significant portion of ambient sulphates in Sri Lanka is coal burning power plants in India26 and a significant portion of the emissions from Sri Lankan coal projects will either be blown into the ocean or end up in other countries. In any event, in a monsoonal climate, dispersion from tall stacks will be very wide: the Puttalam site is in one of Sri Lanka’s windiest locations. Moreover, air quality concentrations in densely populated urban areas will be largely determined by transportation sector emissions, and in the specific case of fine particulate matter, confounded by road dust. Rigorous epidemiological studies are even more complicated, and consequently are few – except in the EU, the USA, and more recently in China (where the scale of air pollution damages from local particulate and SO2 emissions was extremely high). Not surprisingly, there are very large uncertainties in the published studies, and estimates of damage costs per kWh vary by orders of magnitude, as shown in Table 10, these range from 6 €-cent/kWh (about $10Uscents/kWh) to 0.1 €-cent/kWh. 26There is a large literature on this subject, particularly with respect to acid rain (forest damage in Scandinavia was shown to be attributable to coal burning power plants in the UK; acid rain damage in Quebec from coal burning power plants in the mid-western States of the USA. A detailed study of Croatia in eastern Europe (by the EKONERG Institute) showed that 87% of SO2 and SO4 levels in Croatia were attributable to emissions from other countries, and that 87% of emissions in Croatia was transported to other countries. The implication is that increasing renewable energy in Croatia would mainly benefit other countries; and that ambient air quality in Croatia was largely determined by emissions by countries outside Croatia (see Frontier Economics, Cost-Benefit Analysis of Renewable Energy in Croatia, Report to the World Bank, 2003. Sri Lanka: Environmental Issues in the Power Sector 34 ECA, RMA and ERM Environmental regulations and standards Table 10 Damage Cost Estimates Study SO2 Particulates NOx Total damage (€/tonne) (€/tonne) (€/tonne) cost for coal (€-cent/kWh) Croatia, Zagreb(a) 13,483 24,218 19,265 6.0 “Representative European Values� 10,450 15,400 15,700 4.8 ExternE(c) UK, ExternE(b) 6,820 14,060 5,740 2.0 Portugal, ExternE (e) 4,959 5,975 5,565 1.8 EU DG Environment (BeTa 5,200 14,000 4,200 1.6 Database)(d) World Bank, Six Cities Study (f) 96 1,723 255 0.1 (a) Ekonerg Study, Table 6.4-6, 2002 (b) AEA, Power Generation and Environment, UK Perspective, Report AEAT 3776, 1998 (c) J. Spadaro and A. Rabl, Air Pollution Damage Estimates: the cost per kg of pollutant, Ecole des Mines de Paris, Centre d’Energetique (d) M. Holland and P. Watkiss, Estimates of the marginal external costs of air pollution in Europe: Benefits Table Database:BeTa, EU DG Environment, 2001 (e) CEETA, Implementation in Portugal of the ExternE accounting Framework, 1998. Table 3.20. (f) K. Lvovsky, G. Hughes, D. Maddison, B. Ostrp and D. Pearce, Environmental Costs of Fossil Fuels, A Rapid Assessment Method with Application to Six Cities, World Bank, Environment Department, Paper 78, October 2000 But precisely because damages are so location specific, aggregate estimates of damages as $/kWh are controversial. Yet in the absence of country specific studies, damage cost estimates have frequently been made using the “benefit transfer method�, wherein estimates from one country are adjusted by per capita income (and population density) to another. In Sri Lanka, given the absence of reliable health impact studies, there would indeed be little choice but to use this method,27 and several earlier studies in Sri Lanka have used the approach (e.g., in a study of the impacts of the 1996 power shortage,28 and the Environmental Impact Assessment of the Colombo-Katunyake Expressway),29 as well as in other countries.30 27 The potential issues involved in the benefit transfer method have been extensively discussed elsewhere. 28 M. Munasinghe, et al., Linkages between Economic Policies and the Environment in Sri Lanka, Lanka International Forum on Environment and Sustainable Development, Working Paper Series, No.1, December 1998. 29Sri Lanka Road Development Authority, Environmental Impact Assessment Report, Colombo-Katunayake Expressway, June 1997 (hereinafter cited as CKE-EIS) 30 For example, several recent studies of energy sector policies and projects in China have used this approach (for application to an assessment of renewable energy generation, see Promoting Renewable Energy in China: An Economic Analysis of a Mandated Market Share Policy, World Bank, April 2001; for an application to a power transmission project, see Yunnan Dachaoshan Power Transmission Project, in Sri Lanka: Environmental Issues in the Power Sector 35 ECA, RMA and ERM Environmental regulations and standards The role of stack height was recognized in a World Bank study of six cities (Santiago, Krakow, Mumbai, Shanghai, Manila and Bangkok),31 which showed order of magnitude differences between emissions from power plants with tall stacks, and emissions at ground level (from self generators, trucks and buses), with emissions from medium stacks (typical of large industries) in between (Table 11). Table 11 Damage costs High stack Medium Stack Low Stack (Power plants) (Large industry) (Self-generation) $(2000)/tonne per 1,000,000 population per $1,000 of per capita income PM10 Range for six cities 20–54 63–348 736–6,435 Average 42 214 3,114 SO2 Range for six cities 3-8 10–56 121–1,037 Average 6 33 487 NOx Range for six cities 1–3 3–13 29–236 Average 2 9 123 Source: K. Lvovsky, G. Hughes, D. Maddison, B. Ostrp and D. Pearce, Environmental Costs of Fossil Fuels, A Rapid Assessment Method with Application to Six Cities, World Bank, Environment Department, Paper 78, October 2000 Abeygunawardena et al., Environment and Economics in Project Preparation: Ten Asian Cases, Asian Development Bank, 1999). 31K. Lvovsky, G. Hughes, D. Maddison, B. Ostrp and D. Pearce, Environmental Costs of Fossil Fuels, A Rapid Assessment Method with Application to Six Cities, World Bank, Environment Department, Paper 78, October 2000 Sri Lanka: Environmental Issues in the Power Sector 36 ECA, RMA and ERM Technology options 5 Technology options This section presents assumptions on the basic generation technology options available for the generation planning model. These are based on information used by the CEB in its own modelling but with a difference in that we use a net rather than gross basis (for reasons explained below). The estimates below also incorporate the latest available information on cost trends. Technologies that were screened out and not considered further in the analysis are described in Annex A7. In additional to generation technology, we also present demand-side technology options that are analysed. Rehabilitation of existing power plants to extend their lives and delay investment should always be considered. CEB has investigated, and continues to investigate the optimum retirement dates for existing plants on a case-by-case basis. However, if given the option, the optimisation model would immediately retire most of the oil-burning power plants as early as possible and would choose more coal and hydropower plants. It does not do this only because the oil burning plants are IPPs with long-term contracts and cannot be retired for contractual reasons. 5.1 CCGT (autodiesel) The CEB Generation Expansion Plan (2009addendum) assumptions for CCGT are shown in Table 1232. CEB uses the term “pure construction cost� for the more generally used “overnight� cost; i.e., cost without IDC (and exclusive of any taxes and duties).33 Table 12 CEB assumptions, CCGT (gross basis) 150 MW 300 MW Capital cost (“pure construction cost�) $/kW 836 676 Auxiliary consumptions % 3 3 Minimum load heat rate kCal/kWh 2614 2457 Average incremental heat rate kCal/kWh 1462 1454 “IDC� % 13.54 13.54 32 CEB uses the term “gas turbine� and hence the abbreviation for combined cycle as CCGT. This report uses “combustion turbine� rather than gas turbine, to preserve the distinction between the technology and the fuel: a CCGT can be fuelled by gas (LNG), auto-diesel, or fuel-oil. 33 For CEB projects, an average of 25% import duty is paid on the foreign component, and 12% VAT on the domestic cost: these are excluded from the economic costs. IPPs benefit from a duty waiver. Sri Lanka: Environmental Issues in the Power Sector 37 ECA, RMA and ERM Technology options In our view, the CEB capital costs are low. A detailed 2008 survey of CCGT costs in the US, India and Romania prepared for the World Bank34 shows Indian CCGT costs at over $1,170/kW. Late 2008 estimates for the 450 MW Non Trach 1 project in Vietnam, currently under construction, are $850/kW, and the current estimate for the 750 MW Non Trach 2 project is $948/kW.35 In 2008, a 726.6 MW CCGT in Tripura, India, had a reported capital cost of $1,226/kW,36 while a 900 MW CCGT in Saudi Arabia had a cost of $1,136/kW. Both of these figures are “contract� costs, and are expected to be substantially higher than overnight costs for reasons explained above. A 2008 World Bank study of Peru used $850/kW as the overnight night cost for (natural gas fired) CCGT37; the same value was also used in the 2009 MIT Nuclear study.38 This value is appropriate for our study as the CCGT overnight cost. In addition, no assumptions are expressly made by CEB for auxiliary consumption, since these are assumed to be included in the load forecast at a constant 1%. As discussed in Section 3.2, this practice of gross-basis calculations in WASP should be replaced by a net basis calculation. The load forecast then represents the actual net requirement at the generation bus, and the differences in auxiliary consumption across plants are properly considered by the net output of each candidate. With this in mind, our WASP model assumptions for auto-diesel CCGT thus convert to net basis assumptions using a typical 3.5% auxiliary station-use allowance, and replace CEB’s assumption on capital costs with a more realistic figure. These assumptions are as shown in Table 13. Table 13 EIPS assumptions, CCGT (auto-diesel) Gross Unit Gross installed Gross installed / Net capacity = capacity = 300 MW 150MW Capital cost (“Pure Gross $/kW 850 950 construction cost�) Construction period Years 3 3 IDC % 13.54 13.54 Economic life Years 30 30 Auxiliary consumption % 0.035 0.035 Net output Net MW 289.5 144.75 Overnight capital cost, Net $/kW 881 984 per kW of net output Minimum load heat Gross kCal/kWh 2457 2614 34 URS, Study of Equipment Prices in the Energy Sector, Report to the World Bank, April 2008. 35 World Bank, Power Generation in Vietnam: Issues and Options, Draft Report, September 2009. 36 http://www.tripurapower.com/. The EPC contractor is BHEL. 37 World Bank, [reference] 38 MIT, [reference] Sri Lanka: Environmental Issues in the Power Sector 38 ECA, RMA and ERM Technology options Gross Unit Gross installed Gross installed / Net capacity = capacity = 300 MW 150MW rate, HHV Net kCal/kWh 2546 2709 Average incremental Gross kCal/kWh 1454 1462 heat rate, HHV Net kCal/kWh 1507 1515 Full load efficiency Gross % 48.1 46.7 Net % 46.6 Schedule maintenance Days 30 30 Forced outage rate % 0.08 0.08 5.2 CCGT (fuel oil) The use of fuel oil for CCGTs is unusual, making data upon which to base assumptions difficult to find. The 300 MW project at Kerawalapitiya on the west coast, commissioned in 2008-2009,39 is the only such plant in South Asia known to us. The total capital cost for this plant is cited as $329million, or $1,096/kW, including IDC. Assuming the latter at 13.54% (Table 12), the economic cost for the WASP model assumptions calculates to $965/kW (based on nameplate rating). With regard to conversion to net basis, the adjusted gross output (taking into account de-rating for fuel oil and ambient operating temperature) is 280 MW. Assuming an auxiliary consumption of 3.5%, the net output is 270.2 MW. The heat rate is not stated in the CEB Generation Expansion Plan report, but one may assume a slight efficiency penalty over auto-diesel, assumed here at 90% of the auto- diesel value. Thus the minimum load gross heat rate for the auto-diesel CCGT as stated by CEB (2,457 kcal/kWh) calculates to 2,533 kcal/kWh, which, when adjusted to a net basis, is 2,625 kcal/kWh (a similar conversion applies to the incremental heat rates). Finally, given the need to frequently wash the turbines, the plant is off-line for one day every two weeks, so scheduled maintenance is an additional 52 days per year (on the basis of 1 day for cooling down, one day for washing and 26 such cycles per year) over and above the standard estimate of 30 days/year, making schedule maintenance 82 days in total. Forced outage rate is assumed at the same rate of 8%. Given these considerations, Table 14 shows the WASP model input assumptions on a net basis. 39 200MWGas turbines commissioned in November 2008; Steam turbine to be commissioned in 2009 Sri Lanka: Environmental Issues in the Power Sector 39 ECA, RMA and ERM Technology options Table 14 EIPS assumptions, CCGT (Fuel oil) Gross / Unit Values Net Size (installed capacity) gross MW 300 De-rated gross output (see text) gross MW 280 Capital cost (“pure construction cost�) gross $/kW 965 construction period, years years 3 IDC % 13.54 Economic life years 30 Auxiliary consumption % 3.5 Net output net MW 270 Overnight capital cost, per kW of net output net $/kW 1072.2 Minimum load heat rate, HHV Gross, adjusted for lower efficiency gross kcal/kWh 2,533 Net net kcal/kWh 2,625 Average incremental heat rate, HHV Gross, adjusted for lower efficiency gross kcal/kWh 1,843 Net net kcal/kWh 1,910 gross % 48.1 Full load efficiency net % 40.0 Scheduled maintenance days days 82 Forced outage rate % 8 5.3 Open cycle combustion turbines The CEB generation planning model includes three sizes of open cycle combustion turbines, CEB’s assumptions for which are shown in Table 15. Table 15 Open-cycle combustion turbine, CEB Assumptions Gross / units 35 MW 75 MW 105 MW Net Capital cost (“pure construction Gross $/kW 630.4 515.2 428.7 cost�) Minimum load heat rate, HHV Gross kCal/kWh 3060 4134 4134 Sri Lanka: Environmental Issues in the Power Sector 40 ECA, RMA and ERM Technology options Gross / units 35 MW 75 MW 105 MW Net Average incremental heat rate, Gross kCal/kWh 3060 2310 2310 HHV Full load efficiency Gross % 28.1 30.1 30.1 Scheduled maintenance days days 30 30 30 Forced outage rate % 8 8 8 As is the case of the CCGTs, CEB’s costs appear low. Figure 19 compares the CEB assumptions with the World Bank/URS study (for India), and a recent project in Tanzania. Figure 19 Cost Assumptions for combustion turbines Consequently we have increased the capital costs from 630.4 $/kW to 700 $/kW for the 35 MW unit, from 515.20 $/kW to 600 $/kW for the 75 MW unit, and from 428.70 $/kW to 500 $/kW for the 105 MW unit, These changes are shown in Table 16, which includes our full set of assumptions on open cycle combustion turbines. Net heat rates are calculated on the basis of an assumed auxiliary consumption of 3%. Sri Lanka: Environmental Issues in the Power Sector 41 ECA, RMA and ERM Technology options Table 16 EIPS Assumptions, open-cycle combustion turbines Gross Unit 35 MW 75 MW 105 MW / Net Capital cost (“pure construction Gross $/kW 700 600 500 cost�) Construction period years 1.5 1.5 1.5 IDC % 6.51 6.51 6.51 Economic life years 20 20 20 Auxiliary consumption % 3 3 3 Net output Net MW 34.0 72.8 101.9 Overnight capital cost, per kW of Net $/kW 722 619 516 net output Minimum load heat rate, HHV Gross kcal/kWh 3,060 4,134 4,134 Net kcal/kWh 3,155 4,262 4,262 Average incremental heat rate, Gross kcal/kWh 3,060 2,310 2,310 HHV Net kcal/kWh 3,155 2,381 2,381 Full load efficiency Gross % 28.1% 29.5% 29.5% Net % 27.3% 28.6% 28.6% Scheduled maintenance days Days 30 30 30 Forced outage rate % 8 8 8 5.4 Supercritical technology for coal generation The CEB expansion plan is based on 300 MW conventional subcritical coal technology. However, many Asian countries are moving to supercritical technology (and in China even ultra supercritical), which offer higher efficiencies (Table 17). Supercritical units are also desirable from the perspective of minimizing CO2 emissions. While a 300 MW subcritical coal project has CO2 emissions of 0.88kgCO2/kWh, a 600 MW supercritical project has emissions of 0.80 kgCO2/kWh, a significant reduction. Table 17 Coal technology efficiencies in China MW Net coal Efficiency, % consumption, g/kWh Ultra super critical 1000 287 43.03 600 292 42.09 Super-critical 299 41.10 Sub-critical 300 340 36.15 Sri Lanka: Environmental Issues in the Power Sector 42 ECA, RMA and ERM Technology options MW Net coal Efficiency, % consumption, g/kWh 100 410 29.98 50 440 27.93 25 500 24.53 12 550 22.35 6 600+ 29.48 Average 2005 367 33.49 Average 2006 357 34.43 Xianxiong Mao: How does China Reduce CO2 Emissions from Coal-fired Power Generation: Activities and Deployment of Clean Coal Power Generation and Carbon Capture in China, World Bank Energy Week, April 2009. Despite these efficiency gains and lower CO2 emissions, CEB has not heretofore considered supercritical units. Supercritical units are not available in 300 MW size units, and their 600 MW minimum size is considered too large given Sri Lanka’s total load of 3,674 MW in 2015 (so 600 MW represents 16% of peak demand), or even 7,815 MW in 2025 (still 7.6 % of peak demand).40 This stems from a concern over reliability, since the loss of any single unit should not generally exceed 10% of the load. Reliability concerns may thus offset the efficiency gains. However, to assess the economic benefits and the lower emissions of supercritical coal- fired power plants, a 600 MW (gross) candidate was retained in this study. As explained later in this Report, in the reference case analysis, 600 MW supercritical units were allowed from the year 2018, by which time, the system peak demand exceeds 4,000 MW. Certainly in a system large enough to absorb 600 MW units, supercritical units offer significant cost savings: the efficiency gains do indeed offset the slightly higher capital costs, as shown in Figure 20. 40 CEB Base Load Forecast, 2009-2022 Expansion Plan, Table 3.2 Sri Lanka: Environmental Issues in the Power Sector 43 ECA, RMA and ERM Technology options Figure 20 600 MW Super-critical coal vs. 300 MW sub-critical coal 5.5 LNG The CEB generation plan does not include an LNG option, a decision consistent with conclusions of various past studies that LNG was not an economic option for Sri Lanka for the foreseeable future.41 However LNG continues to be suggested by some private developers and NGOs, and JICA is reported to be conducting a study (one of many) of the LNG option. The latest such proposal is by Lanka Aloka AB(Pvt)Ltd.42 Even though not described as such, this is in fact a proposal for a so-called merchant plant, with the entire capital costs of the project, including LNG terminal, regasification and the 488 MW CCGT power plant proposed to be financed by a foreign investor. Sales are to CEB based on a one part energy tariff on “merit order basis�. No merchant LNG project exists in Asia for the very good reason that with merit order dispatch the LNG plant would be dispatched for so few hours in the year that recovery of capital costs is extremely unlikely.43 IPP CCGT projects in Asia run under take-or- pay contracts, even where the entire gas price risk is assumed by the buyer (such as the IPP CCGTs at Vietnam’s Phu My complex). 41The conclusion of a 2001 World Bank Study and a 2003 USAID Study was that it is highly doubtful that the proposal will actually being financed whatever the financial credibility and capacity of the project sponsors. 42 Kerawalapitiya gas power plant: A positive step, The Nation, July 16, 2009 43 The capital cost for this proposal has been reported as $600million, which works out at $1,234/kW. Sri Lanka: Environmental Issues in the Power Sector 44 ECA, RMA and ERM Technology options The most frequently cited “small� LNG-based power project is the EcoElectrica project in Puerto Rico.44 If the capital cost estimate of $670million (which one encounters in press reports) for 507MW is correct, the unit cost calculates to 1,320$/kW (more expensive than the $1,374/kW used by CEB for coal). If the power generation component (CCGT) costs $604/kW (CEB’s CCGT cost for a 300 MW unit), its cost is $306 million, so the balance of $364 million would be for the LNG terminal - a very high up-front cost (though it seems there is quite a bit of spare capacity in the terminal). It is possible that these costs include the cost of a desalinisation plant as the project has agreement to supply potable water to the adjacent Puerto Rico Aqueduct and Sewer Authority. Unfortunately, more precise information on the EcoElectrica project is limited, the reason for which may be the bankruptcy of the project’s sponsor, ENRON. Regardless, the question remains whether LNG is a viable option for Sri Lanka. As such, one must consider issues surrounding LNG’s transportation along with both generation and non-generation uses, the latter of which would be required to achieve the required economies of scale. Each of these is discussed below. 5.5.1 LNG transportation options If pipeline supply from India is excluded, the transportation options are as follows: Larger (>100,000 m3) LNG tankers serving South Indian projects (e.g. Cochin) could make their return journey via Sri Lanka, retaining in their holds such smaller quantities as may be required in Sri Lanka. However, whether the large LNG vessels used to supply Cochin would be suitable for the relatively shallow waters of the west coast is unclear. Moreover, the long length of jetty required even to reach 15 metre minimum water depth imposes additional costs and handling difficulties. The optimal configuration (as would be possible at Trincomalee, and as is practiced at typical Japanese terminals) calls for compact arrangement of unloading point, storage and regasification. Small LNG carrier (30,000 m3) under direct charter, directly supplying a 2 x 300 MW scale project. Backhaul supply, as suggest by ENRON in 1999 for the purpose of supplying a smaller Sri Lanka project.45 This modality envisioned large LNG tankers from the Gulf supplying Japan, and which normally returned empty, instead stopping at an Indonesian LNG terminal (such as Arun at the tip of Sumatra) to take on a partial shipment destined for Sri Lanka. This would be unloaded at a Sri Lanka port (a southern location such as Galle would involve the shortest detour), after which the tanker would again be empty and return to the Gulf. Though the incremental travel distance to an Indonesian (or Malaysian) LNG terminal would be relatively 44 Previously, most of Puerto Rico’s generating capacity was based on bunker fuel oil. 45Natural gas as a fuel option for power generation in Sri Lanka, Presentation to the Ceylon Electricity Board, June 1999, Enron International. Sri Lanka: Environmental Issues in the Power Sector 45 ECA, RMA and ERM Technology options small, additional loading and unloading times would also add to costs. Nevertheless, the total shipment cost may be lower than those of the other two options. 5.5.2 LNG for power generation One of the major hurdles for producing power from LNG is the actual cost of the LNG. What this price would be for Sri Lanka is difficult to estimate. Indeed, in 2006, JICA conducted a study looking at a “natural gas option� for Sri Lanka, with the gas becoming available in 2020. However, the price assumptions in the JICA study are unclear.46 The price of imported natural gas is generally linked to the price of oil. Therefore the price was set on the basis of the average price of crude oil (cif Colombo,$42/bbl May 2004-April 2005), and based on the relationship between the prices of imported crude and natural gas in Japan at $6/bbl. Natural gas is certainly not priced in $/bbl, and presumably what is meant is that, on a BTU basis, LNG is priced lower by the corresponding equivalent of $6/bbl. In light of the discussion in Annex A5.1.4 on the relative price of LNG and crude oil, this assumption may be questionable. Beyond the issue of price, the use of LNG would certainly result in lower GHG emissions than coal, although this would come at very high cost. Equivalent emission reductions might well be achieved by renewable energy options at lower cost. There are also important siting limitations. For safety reasons LNG tankers could not be unloaded at west coast locations during the monsoon season, requiring expensive storage on-land facilities to cover the monsoon season demand, dual fuel capability (as provided at Dabhol), or an East Coast (Trincomalee Bay) location. It has been suggested that floating storage LNG units might be used – these are LNG vessels converted to floating storage units to provide regasification.47 Other tankers would supply this unit from the LNG source. However, one may note that: The concept is still in the design stage, and costs are not known; and The conceptual design calls for “benign environmental conditions for the terminal location�. The cost of the smallest LNG terminal that could reasonably be built in Sri Lanka – about 1mtpa, equivalent to the requirements for 1000 MW of CCGT capacity - has been estimated by a USAID study at $300million for 1mtpa.48 With 1 tonne of LNG equivalent to 51.7mmBTU, and annualising the capital cost over 25 years at 10% 46 The study nowhere uses the term “LNG�! 47 Golar LNG, Floating Storage and Regasification Unit 48LNG terminal and regasification capital costs have declined over the past few years. In 1999, Tokyo Electric power estimated the cost of terminal and regasification at for a 750 MW scale development at $480 million. (Tokyo Electric Power Services, Ltd, Kerawalapitiya CCGT Detailed Feasibility Study). Sri Lanka: Environmental Issues in the Power Sector 46 ECA, RMA and ERM Technology options discount rate, this results in a capital cost of $0.64/mmBTU. Fixed operating costs (including maintenance and security) can be taken at 3% of capital costs,49 (equivalent to $0.17/mmBTU). The variable cost of regasification can be taken as $0.03/mmBTU.50 This thus gives a total terminal cost of $0.84/mmBTU. This high cost is one of the reasons why most LNG projects are at much larger scale, typically at least 2mtpa. Therefore, if throughput is at capacity, the delivered cost of LNG is as shown in Table 18. Table 18 Delivered cost of LNG 75 $/bbl 125 $/bbl Crude oil price $/mmBTU 12.93 21.55 IEA forecast, relative LNG price 0.77 0.77 cif Japan $/mmBTU 9.96 16.59 Less shipping Qatar-Japan $/mmBTU 1.00 1.00 FOB Qatar $/mmBTU 8.96 15.59 Shipping $/mmBTU 0.50 0.50 Terminal capital cost $/mmBTU 0.64 0.64 Fixed O&M, terminal $/mmBTU 0.17 0.17 Variable $/mmBTU 0.03 0.03 Total (1) $/mmBTU 10.30 16.93 cif Sri Lanka(2) $/mmBTU 9.49 16.12 (1) valid only when terminal capacity of 1 mtpa is fully loaded (1200MW) (2) excluding terminal capital recovery and terminal fixed O&M costs The LNG fuel cost is $10.30/mmBTU only if 4 x 300 MW CCGTs are in place, and the 1 mtpa terminal is fully utilized. As shown in Table 19 a 300 MW CCGT at 50% load 49M. Tusiani and G.Shearer, LNG: a Non-technical Guide, Pennwell Books, 2007, cites a range of 3-4%, so 3% seems appropriate for Sri Lanka. 50 Most Asian LNG projects use open rack vaporizers (ORV), which use seawater as its heat source. By running seawater over the aluminum tubes, the LNG inside the tubes converts from a liquid into a gas. Because this method is very cost-efficient to operate and consists of a simplistic structure, it is easy to operate and maintain, and only uses fuel gas vaporisers for backup. In the US, environmental regulations do not allow this technology, and therefore most US terminals use fuel gas vaporisers which use about 1.5% of the fuel throughput (see Tusiani and Shearer, op.cit. At 1.5% of cif fuel cost at 75$/bbl, this computes to $0.12/mmBTU: the corresponding variable cost for ORV would be no more than 10% of this, so $0.012/mmBTU. Sri Lanka: Environmental Issues in the Power Sector 47 ECA, RMA and ERM Technology options factor consumes about 0.19 mtpa of LNG. If an LNG unit replaces coal baseload in the expansion plan, a 1mtpa terminal would suffice for 1,136 MW of CCGT operated at 70% capacity factor. Table 19 LNG consumption 300 MW 300 MW 1,136 MW Average efficiency % 0.46 0.46 0.46 Average heat rate BTU/kWh 7,417 7,417 7,417 Average capacity factor % 0.5 0.7 0.7 Generation GWh/year 1,314 1,839.6 6,966 Fuel requirement mmBTU x 10^6 10 14 52 mmBTU/tonne 51.7 51.7 51.7 LNG mtpa 0.19 0.26 1.00 With regard to the implications for the generation planning model, the high cost will mean that the LNG option will never be chosen. Thus, if it is to be considered, entry must be forced. This forcing comes in the form of a 4 x 300MW LNG-fuelled CCGTs inserted to replace coal units, and the capital costs of the terminal, and the fixed O&M costs, added (externally to WASP) for every fourth unit. The capital costs and heat rates of the LNG-fuelled power blocks would be the same as for auto-diesel-fired units. 5.5.3 Non-power use of LNG In order to benefit from the economies of scale of LNG, it is clear that a project of economic size in Sri Lanka would require substantial non-power gas use. However, unlike other countries in South Asia that already have a gas pipeline and distribution system, huge investments would be required to establish a new system. Sri Lanka also lacks large energy-intensive industries that could easily switch from oil to gas were the latter to become available. Of course, it may be argued that every country that now has a domestic gas-pipeline system had to begin at some point. However, we know of no example anywhere in the world where such a pipeline system was started on the basis of LNG imports. In every example known to us, the impetus for a gas pipeline system was the discovery of domestic gas reserves (e.g. in India, Pakistan), or access to gas pipelines fed by gas-rich neighbours (e.g. Switzerland supplied from North Africa via Italy, or Spain supplied from Algeria via Morocco). Although LNG is readily injected into an existing pipeline system (e.g. in the US, where east coast LNG projects were seen as a way of meeting high-value winter heating demand peaks, or as in many of the proposed Indian LNG Sri Lanka: Environmental Issues in the Power Sector 48 ECA, RMA and ERM Technology options projects),51 a gas pipeline system based entirely on imported LNG seems hard to envisage. 5.6 Petroleum Coke A refinery project by Ceylon Petroleum Corporation (CPC) is presently under discussion. Whether this will be an expansion of the existing refinery, or a new refinery, has yet to be decided, and process and crude source optimisation has yet to be completed. This optimisation may be influenced by the forecast reduction of fuel oil demand52 for power generation owing to the introduction of coal fired power plants, and whether petcoke is a revenue generating product (which would be the case if it can be used at the coal project), or merely a waste product. The possibility of burning petcoke in the coal-fired power plants has been discussed, but no firm decision has been made by CEB on this issue. Petcoke would be produced in a so-called delayed coker, which heats vacuum bottoms to its thermal cracking temperature, producing gasoil and a carbon residue known as petcoke.53 The rationale for cokers is to increase gasoil and reduce fuel oil output, which is desirable for Sri Lanka given the gradual reduction of fuel oil for power generation over the next decade. The vacuum bottoms from Iranian light crude would typically yield 23% petcoke, 27% from Iranian heavy. With the new refinery potentially sized at 100,000 barrels per day (bpd), some 900 tonnes of petcoke would be produced per day (Table 20). Transport to the coal project in Puttalam would be by train (125 km) and then truck to site (13km). The daily output would require 1-2 trains per day. Table 20 Petcoke yield Units Crude bpd 100,000 Density Bbl/tonne 7.5 Crude tpd 13,333 Vacuum bottoms [] 0.25 tpd 3,333 Petcoke yield [] 0.275 51Proposed projects in Gujarat contemplate injecting LNG into the existing HBJ pipeline constructed to bring India's domestic off-shore gas reserves to the industrial regions of Gujarat and the Delhi metropolitan area. 52All the nine IPPs except one use fuel oil, and by year 2020, only one fuel-oil burning IPP would still have an active PPA with CEB. Additionally, at least one of CEB’s of fuel-oil burning power plants would be retired. CEB’s generation expansion plan forecasts that the fuel oil requirements for power generation would decline from 754 MT in year 2010 to 30 MT in year 2020. 53Cokers are increasingly used in the United States, and petcoke supplied as a fuel for power generation, though proportion is small: in 2006, 7.3million tonnes were so used in the USA (compared to 1,030 million tonnes of coal). Sri Lanka: Environmental Issues in the Power Sector 49 ECA, RMA and ERM Technology options tpd 917 Assuming right equivalence of heat values,54 this production of petcoke accounts for 36% of the coal input of Stage I of the Puttalam coal project, or 12% for the entire 900 MW project (Table 21). Table 21 Petcoke v coal Unit 300 MW 900 MW Coal project tpy 700,000 2,100,000 Plant factor 0.75 0.75 tpd 2557 7671 Petcoke tpd 917 917 as % 36% 12% Petcoke tends to have high sulphur concentrations (4% to 7%), and would need CFB to provide 100% of the feedstock for power generation. Its cif price (as $/mmBTU) at the coal plant gate will reflect that of its closest substitute, coal, adjusted for any incremental on-site handling costs, and its impact on FGD costs. Coke is produced as fist-sized lumps, and would require pulverisation. Large scale international trade appears to be limited to the Americas. Spot price assessments are published by Platts International Coal report, with current prices highest on the US west coast. July 2009 prices are in the range of $20 to $41/tonne, significantly lower than coal prices. Table 22 Platt’s petcoke spot price assessments Origin sulphur current price range, $/tonne, fob vessel US Gulf 6-6.5% 20-29 5-8% 25-32 4-5.5% 25-37 US west coast 4% 36-41 54There is no detailed information yet available on its heat value: however, since petcoke is largely pure carbon plus some sulphur, its HHV is not likely to be significantly different to coal. If Petcoke is 95% carbon, its HHV will be 13395BTU/lb, or 7,427 kcal/kg (compared to 6300 kcal/kg of Australian export coal). Sri Lanka: Environmental Issues in the Power Sector 50 ECA, RMA and ERM Technology options Venezuela 4% 25-35 Source: Platts International Coal report, July 13, 2009. Table 23 shows the impact on the sulphur balance, assuming petcoke accounts for 12% of the heat input of the 900MW project (Stage I+II). The weighted average sulphur content would be 1.3%, so with 75% sulphur removed in the FGD, the equivalent sulphur content in the fuel is 0.3%, which would have corresponding emissions well within the stack emission standard. Table 23 Sulphur balance if Petcoke is used in Puttalam power plant %S coal. tpd Sulphur, tpd Coal 0.8% 6755 54.0 Petcoke 5.0% 917 45.8 Average 1.3% 7671 99.9 FGD removal 75% Equivalent 0.3% All other things equal, while sulphur air emissions from the coal plant would be higher if petcoke is used as a fuel than if it is not, emissions from the refinery (or from fuel oil combustion) would be correspondingly lower. Assuming that petcoke is priced at its coal equivalent, the financial impact on CEB (as the operator of the coal project) is at worst zero, and at best positive (depending on how any surplus is apportioned between CEB as the buyer and CPC as the seller). The economic impact (i.e., from the perspective of Sri Lanka) is also likely to be positive (though without a combined optimisation of the power sector and the refinery sectors, precise estimates are speculative). Even though petcoke is a waste product for the refinery, and might be viewed as having zero opportunity (and hence economic) cost, in the absence of assured petcoke offtake, the optimal configuration of the refinery will be different, with a higher fuel oil production as a consequence. If fuel oil has to be exported (for lack of domestic users), its economic value would be its Singapore spot price less freight, as has been the case until the mid-1980s when CEB installed generating plants to use the refinery fuel oil surplus. The necessary combined refinery and coal procurement optimisation lies beyond the scope of this study, and consequently a detailed petroleum coke utilization scenario has not been included here. However, we can say that it is highly probable that if judged technical feasible, and financially advantageous to both CEB and CPC, the economic and local air emission attributes would improve. Sri Lanka: Environmental Issues in the Power Sector 51 ECA, RMA and ERM Technology options 5.7 Indo-Lanka interconnection In CEB’s 2009-2022 LTGEP prepared in 2008, a proposed interconnection between Sri Lanka and India, depicted in Figure 21, was modelled with an investment of 698.4 USD/kW and a delivered price of 6.71 UScents/kWh. A study by NEXANT asserted a delivered price of 6.5 to 8 UScents/kWh although no explanation for this range was provided. It came into the least-cost solution in the year 2022 and had a capacity factor of 33.8% (similar to that of hydropower plants). It entered the least-cost solution in CEB’s no-coal case, high demand case and under high fuel prices scenarios. Our own screening analysis of this option is presented in Section 5.11 below. Figure 21 Indo-Lanka interconnection Sri Lanka: Environmental Issues in the Power Sector 52 ECA, RMA and ERM Technology options Given Tamil Nadu, the Indian point of interconnection, is not in surplus, any 500 MW commitment would have to come from the one region that is in surplus, namely the East. This would imply an additional wheeling charge from there. Of course a coal IPP located in Tamil Nadu itself, using imported coal, could dedicate 500 MW of its output to Sri Lanka. It is questionable, however, whether the scale economies of generating this power at a larger plant would offset the incremental transmission costs. The relevant comparison is thus between the cost of a 2,000 MW imported coal project in Tamil Nadu, say using supercritical technology, and a 2 x 285 MW (net) project on the west coast. The extent to which the benefits would accrue to Sri Lanka will be based on negotiation, although one might assume that the scale benefits were split 50/50. 5.8 Summary of conventional technologies Key characteristic of candidate conventional technologies are summarised in Table 24 and Table 25. As this is an economic study, we make no reference to the financing method (whether the power plants would be CEB’s own or IPPs). Table 24 Technical characteristics of candidate technologies Candidate Full Load Min Load Heat Rate Heat Rate Full Load FOR Max (MW, net) (MW, net) HHV at HHV at Efficiency Capacity min load avg inc Factor (kcal/kWh (kcal/kWh net) net) CGT 35 34.7 34.7 3091 3091 27.8% 8% 84.4% CGT 75 74.3 24.8 4176 2333 29.2% 8% 84.4% CGT 105 104.0 34.7 4176 2333 29.2% 8% 84.4% CC HFO 270.2 90.1 2625 1910 40.0% 8% 71.3% CC DSL 291.0 97.0 2533 1499 46.6% 8% 84.4% CC LNG 291.0 97.0 2533 1499 46.6% 8% 84.4% COL Sub 285.1 85.5 3540 1791 37.1% 3% 86.4% COL Sup 552.0 165.6 3248 1613 40.9% 3% 86.4% Note: See Annex A8 for an explanation of the candidate plant codes used. Table 25 Economic characteristics of candidate technologies Candidate Pure Construction Economic Scheduled Fixed O&M Variable Investment Period Life Maint. (USD/kWm O&M (US (USD/kW, (Years) (days/year) onth) Cents/kWh) net) Sri Lanka: Environmental Issues in the Power Sector 53 ECA, RMA and ERM Technology options CGT 35 700 1.5 20 30 0.577 0.497 CGT 75 600 1.5 20 30 0.497 0.396 CGT 105 500 1.5 20 30 0.437 0.347 CC HFO 965 3 30 82 0.405 0.346 CC DSL 850 3 30 30 0.330 0.283 CC LNG 850 3 30 30 0.330 0.283 COL Sub 1398 4 35 40 0.636 0.249 COL Sup 1438 4 35 40 0.779 0.305 Note: See Annex A8 for an explanation of the candidate plant codes used. These candidates are in addition to the existing power plants/technologies shown in Table 26 and Table 27. Table 26 Technical characteristics of existing generation plant Existing Power Units Unit Net Unit Net Heat Rate Heat Rate Full Load FOR Max Plant Capacity Min at Min at avg inc Efficiency Capacity (MW) Operating Load (kcal/kWh Factor Level (MW) (kcal/kWh net) net) CEB Power Plants55 Kelanitissa-GT 5 16.0 16.0 4662 4662 18.4% 20% 72.1% (Old) [GTSM] Kelanitissa-GT 1 114.2 80.6 3238 2755 27.8% 10% 87.5% (New) [GT7] Kelanitissa- Combined 1 161.7 71.1 2195 1908 42.3% 6% 85.9% Cycle [CCKP] Sapugaskanda- 4 17.4 17.4 2442 2442 35.2% 17% 71.6% Diesel [DSP] Sapugaskanda- Diesel (Ext) 8 8.7 8.7 2261 2261 38.0% 12% 75.9% [DSPX] Independent Power Producers56 Lakdhanavi 4 6 6 2424 2424 35.5% 5.0% 79.1% Diesel [DLDL] Asia Power 8 6 6 2411 2411 35.7% 4.9% 76.9% 55 Characteristics published (and previously used by CEB in planning studies) were converted from gross to net, by taking the average auxiliary power consumption reported by CEB over three years (2005-7). IPP contracts are already in net terms, and were not adjusted. Codes used in WASP are shown in square brackets next to the plant type. 56 Data from CEB planning report 2008. Heat rates reflect the contracted fuel consumption per net kWh. Maximum capacity factor reflects the minimum guaranteed energy in contracts. Scheduled maintenance days have been determined to allow the power plant to provide the minimum guaranteed energy should the economic dispatch select the power plant to operate. Codes used in WASP are shown in square brackets next to the plant type. Sri Lanka: Environmental Issues in the Power Sector 54 ECA, RMA and ERM Technology options Existing Power Units Unit Net Unit Net Heat Rate Heat Rate Full Load FOR Max Plant Capacity Min at Min at avg inc Efficiency Capacity (MW) Operating Load (kcal/kWh Factor Level (MW) (kcal/kWh net) net) Diesel [DAPL] AES Combined 1 163 49 3287 1308 45.2% 1.6% 93.3% Cycle [CAES] Colombo Power 4 15 15 2328 2328 36.9% 5.0% 79.9% Diesel [DCPL] Horana Diesel 4 5 5 2426 2426 35.4% 0.7% 95.5% [DHOR] Matara Diesel 4 5 5 2439 2439 35.3% 2.1% 95.5% [DMAT] Puttalam Diesel 6 17 17 2085 2085 41.2% 2.6% 80.1% [DPUT] Embilipitiya 14 7 7 2382 2382 36.1% 4.5% 80.1% Diesel [DEMB] Kerawalapitiya Gas Turbine 0 90 30 5100 2433 25.9% 8.0% 76.9% [GTKW] Kerawalapitiya Combined- 0 135 50 3225 1540 39.7% 8.0% 76.9% Cycle [CCKW] Table 27 Economic characteristics of existing generation plant Existing Power Plant Scheduled Fixed O&M (USD/kW- Variable O&M (US Maintenance net/month) Cents/kWh-net) (Days/Year) CEB Power Plants [code] Kelanitissa-GT 36 0.357 0.240 (Old)[GTSM] Kelanitissa-GT (New) 10 0.377 0.291 [GT7] Kelanitissa-Combined 30 1.785 0.162 Cycle [CCKP] Sapugaskanda-Diesel 50 2.693 0.970 [DSP] Sapugaskanda-Diesel (Ext) 50 4.192 0.735 [DSPX] Independent Power Producers [code] Lakdhanavi Diesel [DLDL] 61 3.010 1.501 Asia Power Diesel [DAPL] 70 3.520 1.023 AES Combined Cycle 19 1.910 0.090 [CAES] Sri Lanka: Environmental Issues in the Power Sector 55 ECA, RMA and ERM Technology options Colombo Power Diesel 58 4.580 0.705 [DCPL] Horana Diesel [DHOR] 14 4.400 0.904 Matara Diesel [DMAT] 9 4.260 0.949 Puttalam Diesel [DPUT] 65 0.540 0.938 Embilipitiya Diesel 59 1.120 0.651 [DEMB] Kerawalapitiya Gas 60 0.620 0.506 Turbine [GTKW] Kerawalapitiya Combined 60 0.550 0.475 Cycle [CCKW] 5.9 Pumped-storage plant The reference case, and almost all of the cases, have the significant feature that the cheaper base load power plants are not fully loaded owing to the load shape of the power system. Figure 22 shows the daily load profile of a typical day in year 2007. Figure 22 Daily load profile on a typical week-day (2007) 2,000 1,800 1,600 Gross Generation (MW) 1,400 1,200 1,000 800 600 400 200 0 00:30 02:00 03:30 05:00 06:30 08:00 09:30 11:00 12:30 14:00 15:30 17:00 18:30 20:00 21:30 23:00 Time The estimated dispatch on a typical day in year 2020 (with all base load power plants in operation) is shown in Figure 23. It is clear that the cheapest base load plants cannot be fully loaded causing them to be operated on part-load or on various modes of daily or weekly cycling. This is not a normal way of operating a power generating system, Sri Lanka: Environmental Issues in the Power Sector 56 ECA, RMA and ERM Technology options with inherent losses when cycling, although the long-term economics of the generating remains least-cost. Building a Pumped Storage Power Plant (PSPP) is one option to provide adequate load to the lower-cost base load generating units, while assisting to provide cheaper energy at the peak time, when compared with the use of fuel oil and other diesel-burning power plant to meet the evening or seasonal peaking/dry-season backup requirements. Figure 23 Demand profile and installed base load capacity in 2020 5000 2020 forecast 4500 Hydro ROR +Coal 4000 +Fuel oil 3500 Capacity (MW) 3000 2500 2000 1500 1000 500 0 00:30 02:00 03:30 05:00 06:30 08:00 09:30 11:00 12:30 14:00 15:30 17:00 18:30 20:00 21:30 23:00 A comparison of the system demand and the base load generating capacity available by year 2020 indicates that a PSPP of about 500 MW (pumping) may be feasible. There are no detailed studies conducted in Sri Lanka on the possible locations, design and costs of pumped storage power plants. Some preliminary studies have been conducted by CEB to locate a suitable site upstream of the Smanalawewa reservoir in the Walawe river catchment in the southern slopes of the central hills of Sri Lanka. It will not be associated with an existing hydroelectric power plant. The location of the downstream reservoir crosses a river, while the upstream reservoir would need to be created and filled with water pumped from the downstream reservoir. This study uses the following indicative basic parameters to develop the case study on the pumped storage option. The exact details need to be developed in a feasibility study, but a conceptual design and the project parameters can be established during this study. Different unit sizes can be considered in the search for an optimal solution, but this study uses a 125 MW generating units size, and some generic information for the purpose of modelling a PSPP to establish its feasibility at a preliminary level. Table 28 gives the parameters used in the generic PSPP. Sri Lanka: Environmental Issues in the Power Sector 57 ECA, RMA and ERM Technology options Table 28 Parameters of a generic pumped storage power plant Parameter Assumed value PSPP installed capacity 500 MW in 4 units of 125 MW each Cycle efficiency 70% Fixed O&M costs 1.5 x the costs of a hydropower project First year of availability 2020 Generation capacity 500 MW Maximum feasible generation 400 GWh/year 5.10 Demand-side management 5.10.1 CFL programme Programmes to promote the use of Compact Flourescent Lightbulbs (CFLs) in Sri Lanka began in 1995. This first programme lasted until 1999 and a total of 172,000 CFLs were provided to the public and this was estimated to have achieved a saving of 47 MW in demand and 64 GWh per year57. CEB continued to provide support to households through a CFL Easy Payment scheme introduced in 2002 whereby households and religious institutions could obtain up to four CFLs and spread the payment over a 12 month period with their electricity bill. In parallel, an energy efficiency labelling scheme for CFLs (and refrigerators) was launched in 2002 based on a star-rating system58. These efforts at promoting CFLs have been very successful and the penetration of CFLs is now reasonably high. In a recent survey59 conducted by RMA of rural households, 76% of households reported having CFL bulbs – though it also reported that 56% of lightbulbs in the surveyed rural households were normal incandescent bulbs. Nevertheless, this represents a good penetration rate and in urban centres the penetration should be higher. Without the current penetration of CFLs, we estimate that peak demand could have been as much as 250 MW higher today – combining energy and peak demand savings. This is broadly consistent with the increase in Sri Lanka’s system load factor (or fall in peak demand relative to the GWh sales). In the five years before the CFL programme was launched in 1995, the system load factor averaged 55.5% but in the most recent five years it has averaged 58.7%. This difference in load factor would have reduced the 57 TATA Power, Review of Technology Best Practice, CEB CFL Loan Program Sri Lanka 58 Developed by CEB, the Sri Lanka Standards Institution (SLSI) and National Engineering Research and Development Centre of Sri Lanka (NERD) Baseline survey of un-electrified and electrified households in the Hambantota District, December 2008, 59 RMA conducted for CEB’s Lighting Sri Lanka Hambantota Project. Sri Lanka: Environmental Issues in the Power Sector 58 ECA, RMA and ERM Technology options peak demand in 2008 by approximately 110 MW. It is, however, difficult to be sure of how much of this improvement in the load factor is due to DSM and how much is due to a more general trend (or indeed, whether in the absence of the DSM programme the trend might have swung the other way with increased electrification leading to a lower system load factor). Additionally, the peak demand data published by CEB and used to calculate the system load factor is only the aggregate of CEB power plant outputs and does not include MW supplied to the grid from embedded generation, whereas the gross generation data include generation from both CEB plants and purchases from embedded generation and independent producers. Therefore, the load factor appears to be artificially increased owing to the under-reporting of peak demand. Since households should, and do, typically place CFLs in the light fittings that are most frequently used60, the greatest benefits of CFLs in reducing peak demand will already have been achieved. Further penetration of CFLs will lower electricity and fuel consumption but the impact per CFL used will tend to be less than the impact of the first wave of CFLs. There may be value in introducing quality standards for CFLs but these standards will tend to lengthen the life of the bulbs rather than reduce the power consumption. Improved standards for CFLs might be introduced more to avoid misleading customers rather than for energy efficiency reasons and would therefore be of less interest to CEB or the Ministry of Energy. A prohibition on the sale of incandescent lightbulbs has been implemented in some countries. This is likely to be considered too intrusive in Sri Lanka at the present time but may nevertheless be considered as part of a DSM scenario. In this scenario we assume households typically have seven lightbulbs and of these three are CFLs and four are incandescent. The prohibition on the sale of incandescent lightbulbs would mean the replacement of incandescent lightbulbs over approximately five years. Assuming these would have been used for an average of 1 hour per day, we estimate a saving of 40 kWh per household per year but, unlike the initial CFLs, this is assumed to be spread more evenly over the evening period and the capacity saving to CEB is reduced. The additional cost, after accounting for the longer life of CFLs, would be approximately $0.30 per household per year. 5.10.2 Other DSM options The other main drivers of peak demand in Sri Lanka, which occurs in the evening, are likely to be TVs and refrigerators. Penetration of TVs is high. One survey shows 89% of recently electrified households in rural areas have at least one TV. In urban areas the penetration should be higher. The issue that faces the design of a DSM programme is the existing stock of televisions by size and type and the transition that would in any case occur from cathode ray tube (CRT) TVs to liquid crystal display (LCD) or plasma high definition TVs. No specific information is currently available on the distribution of TVs in terms of screen size and 60 The survey of Hambantota district cited above found that the bulbs that are used most are the CFLs. Sri Lanka: Environmental Issues in the Power Sector 59 ECA, RMA and ERM Technology options technology, but it may safely be assumed that the 21 inch CRT is the most widely used type of television today in Sri Lanka. Published information indicates that the average power consumption of a 21 inch CRT is 71.4 W. CRT TVs tend not to be sold anymore in developed western countries but are still sold in Sri Lanka’s shops because of their lower price and they tend to be the first choice of low to middle income families when purchasing a TV for the first time or as a replacement. LCD and plasma TVs are also widely available in Sri Lanka’s shops, but the screen sizes available from most vendors are much larger than the standard 21 inch CRT TV. Most vendors promote LCD models in the range 29 to 32 inches, which according to published literature, would cause the power consumption from TVs to increase61, not as result of transfer from CRT to LCD but as a result of reaching larger screen sizes. A programme to introduce minimum standards for power consumption of TVs would be valuable in reducing peak demand in the coming few years. TVs tend to have a typical life of around five to ten years, so the impact would be felt within a few years. Penetration of air conditioners in households in Sri Lanka is not substantial. Air conditioning is used in commercial premises during the day time but the system peak does not occur during the day, so the benefit of peak demand reduction is not so great. It may be valuable to introduce minimum efficiency standards for air conditioners to reduce the daytime demand, which would tend to reduce energy production and fuel consumption, but we have not considered this in the present analyses. Time-of-use tariffs are offered by CEB with the peak energy price imposed during the peak hours from 6.30pm to 10.30pm being some three to four times the off-peak energy price. The off-peak energy price is 10% to 25% lower than the standard non-TOU tariff. However, a relatively small proportion of GWh sales are sold on the TOU tariff and this low take-up of the TOU may actually reflect the relatively high on-peak tariff which discourages the uptake of this tariff option. Consideration might be given to the structure of the TOU tariffs or possibly to making the TOU tariff mandatory for large users (rather than voluntary as at present). However, given the uncertainty over the response to TOU tariffs and without more broad-based load research to examine likely customer responses, we do not consider a revision to the TOU tariffs for the purposes of the DSM strategy. 5.11 Screening Analysis All thermal power plant candidates were included in the screening analysis, with levelised cost/kWh as the parameter varying with annual capacity factor. Hydro and NCRE power plants (in which energy, and therefore the capacity factor is “fixed�, meaning that they can operate only as long as the resource is available) we included in the analysis as fixed points on the analysis plane. Figure 28 gives the results. 61 The basics of TV power, David Katzmaier and Matthew Moskovciak, November 13, 2009. Among a large number of LCD type televisions tested, only two models, both LCD, had a power consumption less than 100 W (LCD 32 inch: 92.1 W, LCD 32 inch: 97.8 W) http://reviews.cnet.com/green-tech/tv-power- test/?tag=contentMain;contentAux Sri Lanka: Environmental Issues in the Power Sector 60 ECA, RMA and ERM Technology options Figure 24 Screening analysis of selected thermal and hydro/NCRE options 50 CGT 35 CGT 75 45 CGT 105 CC HFO CC DSL CC LNG 40 COL Sub COL Sup Small hydro Small Wind Economic Cost (UScts/kWh) 35 Small Biomass Umaoya Broadlands Ging Ganga 30 Moragolla 25 20 15 10 5 - 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% Annual Plant Factor Note: See Annex A8 for an explanation of the candidate plant codes used above. The two coal candidates are economical over a wide range of annual plant factors. The placement of hydro and NCRE candidates provides an indication of how economically competitive they are, compared with each technology. To analyse the economic benefits of a possible India-Sri Lanka grid interconnection, a limited screening analysis is provided in Figure 25. The key assumptions used in the analysis were: Investment 700 USD/kW (for the interconnection and associated overland transmission links/improvements) Source A supercritical coal-fired power plant in Tamil Nadu (therefore no additional wheeling charges are applied) Losses 2% O&M cost add 10% to the O&M costs of a supercritical coal plant The analysis indicates that over the full range of capacity factors, an interconnection served by a dedicated supercritical coal-fired power plant would be more expensive than Sri Lanka’s own sub/supercritical coal options. The interconnection would be economical for base load service only if Sri Lanka is not able to build coal-fired power plants. Thus, cheaper baseload energy can be available through an interconnection only if LNG or fuel-oil based combined-cycle power plants are selected in Sri Lanka. The breakeven annual capacity factor with an LNG or fuel oil combined-cycle power plants is around 30% (ie., the interconnector would be least-cost if it is not possible to build coal-fired power plants in Sri Lanka and if the interconnector utilisation is greater than 30% of its capacity). Sri Lanka: Environmental Issues in the Power Sector 61 ECA, RMA and ERM Technology options The economics of the proposed interconnection warrants further analysis on the issue of peak-time/dry-season transfers to Sri Lanka from India, and off-peak and wet- season transfers from Sri Lanka to India. Forecasts of surpluses and deficits in Tamil Nadu would be required for such an analysis, along with forecast pricing on the Indian grid. More details of surpluses in other regions of India and likely prices and wheeling charges would also be required to give more robust answers. Figure 25 Preliminary Screening Analysis of India-Sri Lanka Interconnection 70 CGT 75 CC HFO 60 Interconn CC LNG Economic Cost (UScts/kWh) 50 COL Sub COL Sup 40 30 20 10 - 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% Annual Plant Factor Note: See Annex A8 for an explanation of the candidate plant codes used above. Sri Lanka: Environmental Issues in the Power Sector 62 ECA, RMA and ERM Policy Scenarios 6 Policy Scenarios Below we consider broad policies whose environmental and cost impacts might be considered as part of the EIPS framework. 6.1 Sector reform 6.1.1 The Electricity Act The history of attempts to reform the electricity sector in Sri Lanka are described in Section 2.1 above and led to Parliamentary approval of the Electricity Act No. 20 of 2009. Importantly, the Act gave responsibility for regulating the electricity sector to the Public Utilities Commission of Sri Lanka (PUCSL) which has responsibility for licensing of the activities of generation, transmission and distribution. The PUCSL was created in 2003 but has only now (in 2009), with passing of the Electricity Act, assumed responsibility for regulation of the electricity sector. Some of the more far reaching components of the proposed reforms were excluded from the Act. In particular, the Act imposes a limitation on private investment in generation capacity above 25 MW. Licensees for generators above 25 MW are required to involve a shareholding by the government or a public corporation or an entity that is more than 50% owned by government62. However, the level of government shareholding in the generator in order to comply with this requirement is not specified in the Act and, instead, is determined by the Secretary to the Treasury and the Minister of Finance. The Act does not allow private ownership of distribution, other than ownership by a company that is more than 50% owned by government. CEB, local authorities and cooperatives may also obtain distribution licenses. The new Act also imposes the restriction that a transmission license can only be issued to CEB. CEB is not required to be unbundled in legal terms but is required to maintain separate accounts for its different licensed businesses – generation, transmission and distribution/supply. Though the Act does not specifically state that a single-buyer model is adopted, the Act allows that licenses issued to generators by PUCSL may include conditions requiring the licensee to sell electricity exclusively to the transmission licensee and other components of the Act are geared toward a single buyer model and no mention is made of third-party access, which effectively closes down the option of independent producers selling to eligible consumers. An important requirement that is specified in the Act and relevant to the current study is that the license issued to the transmission licensee must include conditions relating to the “purchase electricity on the most economically advantageous terms�. This implies that 62 CEB may also be issued with a generation licence whatever its ownership by government. Sri Lanka: Environmental Issues in the Power Sector 63 ECA, RMA and ERM Policy Scenarios cost minimisation is one of the important duties of the transmission licensee. But the Act also requires that generation licences should contain conditions requiring licensees to comply with environmental laws in force. Another important provision of the Act is that the Minister has powers to formulate general policy guidelines for the electricity sector that take into account the requirements for Sri Lanka in relation to “fuel diversity and the preferred fuel for new electricity generation�. 6.1.2 Implications of reforms for environmental impacts Electricity reform could potentially impact on the environment in diverse ways. Private participation and reforms will tend to give a stronger focus to cost minimisation. While cost minimisation in the absence of environmental regulation can lead to deterioration in the environmental conditions, private participation can sit comfortably in combination with well enforced environmental regulations and clear policies that encourage sustainable use of energy including feed-in tariff arrangements that encourage renewable energy schemes. Ways in which reform can impact on the environment include: A more efficient electricity sector would tend to have lower technical losses and this would mean lower electricity generation to meet a given level of demand. Cost-reflective tariffs could lead some consumers to use electricity more carefully but could potentially lead to lower prices for some customers and this could encourage less careful use of electricity. Generally, however, cost reflective tariffs tend to lead to a more efficient use of electricity and lower consumption of fuels and other resources. Private participation in electricity will tend to lead to higher costs of capital and this will tend to discourage the use of more capital intensive technologies such as coal-fired steam or LNG and would tend to favour CCGT and diesel plants using petroleum products which, as described later in the Report, can be more environmentally unfriendly than coal-fired steam plants. In the search for more and more IPPs, this indeed happened in Sri Lanka from 1996 to 2005, and resulted in a proliferation of oil-fired diesel and CCGTs most of which were outside the least-cost plans CEB continued to publish annually, causing production costs to increase substantially. 6.1.3 Implications for the current study The more significant environmental benefits from reform that are expected in other countries are likely to be less substantial in Sri Lanka. For example, losses are 15.7% in Sri Lanka (including generation, transmission and distribution losses and non-technical losses), which are low by comparison with other countries in South Asia where losses are 30% or more. Tariffs in Sri Lanka are also high by regional standards and, while they did not fully cover current the very high costs in the period when international oil prices were high, with the recent decline in costs and the expectation that costs will fall Sri Lanka: Environmental Issues in the Power Sector 64 ECA, RMA and ERM Policy Scenarios further as more cost-efficient power plants begin to take over from the expensive oil- fired plant, there is less likely to be a need for a radical reform in the level of tariffs. In these circumstances, further reform is not on the policy agenda and a period of consolidation of the regulatory duties of PUCSL may be appropriate to allow the current framework to begin to function effectively before any further fundamental change is contemplated. For the above reasons, a policy reform case was not considered. 6.2 Renewable energy targets 6.2.1 Sri Lanka’s renewable energy policy In year 2008, 40.2% of electricity served through the national grid was sourced from renewable energy sources, almost all of it from hydroelectric sources. The world average is estimated to be about 16.1% of electricity being produced from hydroelectric sources, which places Sri Lanka in a favourable position. As seen in various policy scenarios analysed during this study, the share of renewable energy use for electricity production in Sri Lanka is fast declining, and is expected to reach 32%63 by year 2015, and would continue to decline to 22% by year 2020. Further development of large-scale hydroelectric power plants would be limited, owing to limitations of sites, and the environmental constraints in building large reservoirs and dams. The Energy Policy and Strategies of Sri Lanka (2006), specifies a target of reaching 10% of grid energy from NCRE by year 2015. Thus the scenario of diminishing contributions from renewable energy to the national grid, as explained above, is expected to be arrested by this new policy initiative. Figure 28 shows the status when the NCRE target is achieved by 2015. In this section we analyse the economic implications of the NCRE initiative of the government, presently being implemented by SEA64 and CEB. Grid-connected electricity generating facilities with an installed capacity of less than 10 MW, owned/operated by private companies, are presently considered as Small Power Plants (SPPs). These SPPs are embedded power plants, because they are connected at medium voltage levels (mostly 33 kV) in the CEB grid, unlike the larger power plants, which are connected at higher voltage levels. Furthermore, embedded power plants in Sri Lanka, being small and dependent on the availability of renewable energy, which is sometimes unpredictable, are not centrally dispatched. Power plant operators dispatch them based on resource availability, and CEB procures all their output at all time, without any option for refusal, as provided for in the attractive 63 Assuming the existing small power plants would continue to operate but no new NCRE projects would be commissioned. 64 Sri Lanka Sustainable Energy Authority is responsible for resource allocation, facilitation and monitoring of renewable energy projects through their development process. CEB is responsible for providing the grid connection, and paying the tariffs. Sri Lanka: Environmental Issues in the Power Sector 65 ECA, RMA and ERM Policy Scenarios power purchase agreement offered to such small (less than 10 MW) renewable energy power plants. The agreement is described in a later section. NCRE that have the technical potential for further development in Sri Lanka, which now qualify for development under the SPP process, are biomass, small hydro, wind, and agricultural waste. Waste heat recovery and combined heat and power developments also qualify for this concession, as well as the use of municipal and industrial waste for power generation. Figure 26 Forecast energy share in the grid with NCRE target of 10% by 2015 100% 90% Coal-fired 80% Share of Generation to Grid Oil-fired 70% Large hydro NCRE 60% 50% 40% 30% 20% 10% 0% 2009 2012 2015 2018 2021 2024 2027 Note: The results represents the scenario developed in case 4 of this study. The Small Power Purchase Agreement (SPPA) offered by Sri Lanka is a standardised, non-negotiable 15-year contract. This contract is used by CEB to purchase energy from embedded power plants. The SPPA is offered only to embedded power plants of which the primary source is either a renewable source, or for power plants using waste heat or using combined heat and power technology. The contract specifies the conditions, current prices and pricing policy on which electricity will be purchased by the CEB. The first SPPA was signed in 1996. Investor confidence in Sri Lanka is so far seen mainly in the development of small hydro, while investors have shown some interest to develop biomass and wind power plants, but with little success. The new tariff policy announced in 2007 has changed this situation, and applications are reported to be flowing in to SEA in large numbers, to develop non-hydro SPPs. The total embedded NCRE power plant capacity was 172 MW by August 2009. Thus, embedded generation is still a small share of system generation. The energy contribution to the grid in 2008 was 433 GWh (4.4% of total generation). Sri Lanka: Environmental Issues in the Power Sector 66 ECA, RMA and ERM Policy Scenarios 6.2.2 Incentives Offered The policy incentives that build-up investor confidence and minimises delays in the development of grid-connected renewable energy projects, are the following: There is no solicitation process; all projects are on a first-come, first-served basis Selection of the site, and project development, equipment selection, entirely decided by the developer The SPP agreement is standardised, non-negotiable (hence avoids lengthy negotiations) The pricing formula is standardised, and uniformly applied to all SPPs (this policy ended for contracts signed in 2006, and was replaced with a cost- based, technology-specific policy from 2007) Projects qualify for Board of Investment (BoI) concessions if they meet the standard criteria laid out by the BoI. In general, projects with an investment exceeding LKR 50 milllion qualify for BoI incentives, which offer duty free import of investment equipment and material, and a tax holiday between 5-8 years, and a concessionary tax rate thereafter Incentives by way of competitive interest rates through the ESD/RERED projects (see later for a description of these projects) Table 29 Purchase price from small power producers (contracts signed until 2006) Dry Season (Feb-Apr) Wet Season (May-Jan) 1996 2.90 2.90 1997 3.38 2.89 1998 3.51 3.14 1999 3.22 2.74 2000 3.11 2.76 2001 4.20 4.00 2002 5.90 5.65 2003 6.06 5.85 2004 5.70 4.95 2005 6.05 6.73 2006 5.30 5.82 2007 7.64 6.94 2008 9.65 8.94 2009 11.17 10.59 Source: Annual SPP tariff announcements by CEB. Sri Lanka: Environmental Issues in the Power Sector 67 ECA, RMA and ERM Policy Scenarios Table 29 shows the prices offered to renewable energy-based electricity generating plants, for contracts signed up to 2006. The new tariff policy was announced in 2007. There have been two tariff announcements since then, one in 2007 and the other in 2008. Table 30 shows the third tariff announcement applicable for contracts signed from 2009 onwards. In this study, we base our analysis on this tariff announcement. The case we studied is explained in Section 7.1 on case definitions. For contracts signed from year 2007 onwards, the tariff policy moved from the technology- neutral tariff to one that is technology-specific, cost-based, with a tiered structure. The new tariff policy provides specific incentives to promote all technologies. In addition to the incentives listed earlier in this section, this tariff has the following incentives: An escalation rate applied for operation and maintenance costs based on market indices For biomass, a fuel cost escalation rate based on market indices Extended contract covering a period of 20 years, which too is extendable further by mutual consent. Previous contracts were for 15 years, and silent about possibilities for extensions. Table 30 Purchase price from small power producers (for contracts signed in 2009) Non- Technology / Source Escalable Escalable escalable Escalable Year 16+ Royalty to Base Fuel Base Govt, paid Base O&M Year Year (year 1- Tariff direct by the (year 1-20) 1-8 9-15 20) to SPP utility (% of total Tariff) Mini-hydro 1.55 None 14.18 5.16 1.62 10% Wind 2.46 None 22.53 8.19 1.62 10% Biomass 1.24 7.14 8.50 3.09 1.62 None Biomass 16yr onwards 1.55 7.14 Agro & Indus waste 1.24 3.56 8.50 3.09 1.62 None Agro & Indus 16yr onwards 1.55 3.56 Municipal Waste 3.13 0.00 12.26 4.46 1.62 None Waste Heat 0.49 0.00 10.15 3.69 1.62 None Sri Lanka: Environmental Issues in the Power Sector 68 ECA, RMA and ERM Policy Scenarios Non- Technology / Source Escalable Escalable escalable Escalable Year 16+ Royalty to Base Fuel Base Govt, paid Base O&M Year Year (year 1- Tariff direct by the (year 1-20) 1-8 9-15 20) to SPP utility (% of total Tariff) Escalation per year from 1st January after 8.06% 5.37% 5.37% the commercial operation date Note: This information is available on the SEA website www.energy.gov.lk. The tariff policy also offers a levelised price, at the option of the developer. Table 31 gives the input parameters for the calculation of tariffs as well as the levelised prices. Table 31 Parameters for NCRE tariff calculations and the levelised tariff option Parameters Used Levelised Capital Fuel O & M, O & M, price Cost (LKR Plant Cost % (Year % (Year offered million/ Factor (LKR/ 1-15) 16-20) (LKR/kWh MW) kWh) ) Mini-hydro 190 3.0% 3.0% 42% None 14.58 Wind 230 3.0% 3.0% 32% None 23.07 Biomass 217 4.0% 5.0% 80% 7.14 18.56 Agro & Indus waste 217 4.0% 5.0% 80% 3.56 13.88 Municipal Waste 313 7.0% 7.0% 80% None 15.31 Waste Heat 217 1.3% 1.3% 67% None 9.55 Common parameters: Debt: equity = 60:40, calculated interest rate: 19.22% Annual return on equity allowed = 22% Discount rate = weighted average cost of capital = 20.33% Levelised price offered Technology LKR/kW USCts/kWh h * Mini-hydro 14.58 12.68 Wind 23.07 20.06 Biomass 18.56 16.14 Agro & Indus waste 13.88 12.07 Sri Lanka: Environmental Issues in the Power Sector 69 ECA, RMA and ERM Policy Scenarios Municipal Waste 15.31 13.31 Waste Heat 9.55 8.31 *converted at 115 LKR/USD Sri Lanka: Environmental Issues in the Power Sector 70 ECA, RMA and ERM Cases 7 Cases A reference case and 14 variants to the reference case were developed and analysed. These 15 cases are described in Section 7.1 below. In Sections 7.2 to 7.8 we make observations on the results some of the fifteen cases developed in this study in terms of investment choices and cost. It should be noted that in each case, a least-cost generation expansion was developed, and the discussion below relates to each least-cost plan. Annex A10 presents the detailed results and Annex A11 describes the results in graphical form. The economic and environmental attributes are discussed subsequently in Section 8. 7.1 Case definitions A large number of technology options and sensitivity studies could be conducted for the Sri Lanka power system in a search for the optimal least-cost solution for long term generation investment. Below we present the short-list of cases decided by the study team in consultation with the Steering Committee to be modelled using the WASP IV analytical tool. The base case, or the reference case, was defined to be the business-as-usual scenario. This case thus follows the current thinking of GoSL and CEB with regard to: a demand forecast reflecting expected long-term economic growth (the demand forecast used was that developed during this study, see Annex A); a complete list of candidate power plants of all the feasible technology options presented to the model (see the candidates described in Section 5); and a fuel price scenario in which the oil and coal prices remain stable in constant terms (see the fuel price scenarios developed in Section 3.3) . No constraints were applied in the selection of power plants among the candidates listed except the 600 MW supercritical units owing to their large unit size in relation to the demand in the Sri Lanka system – it was assumed that they could not be commissioned before 2018 when demand reaches 4,000 MW. Thereafter, they were allowed to be chosen by WASP purely based on their economic merits. Once the reference case results were available, a number of policy options were considered. These cases generally involve ‘forcing’ the model to select certain options despite their higher costs. The 14 variant cases are described in Annex A6 and summarised in Table 32 below. Sri Lanka: Environmental Issues in the Power Sector 71 ECA, RMA and ERM Cases Table 32 Summary of cases Case Policy option / scenario Demand Fuel prices Discount rate Fuel price forecast escalation 1 Reference Case EIPS base EIPS 1 10% 0% Alternatives to the Reference Case 2 LNG forced EIPS base EIPS 1 10% 0% 3 Small / medium EIPS base EIPS 1 10% 0% hydropower forced 4 NCRE forced EIPS base EIPS 1 10% 0% 5 Cases 2, 3, and 4 combined EIPS base EIPS 1 10% 0% 6 Coal after Trincomalee to be EIPS base EIPS 1 10% 0% supercritical 7 No coal built after present EIPS base EIPS 1 10% 0% commitments 8 Pumped storage power plant EIPS base EIPS 1 10% 0% 9 DSM intervention EIPS base EIPS 1 10% 0% Sensitivities around the Reference Case 10 Higher demand forecast EIPS high EIPS 1 10% 0% 11 Higher fuel prices EIPS base EIPS 2 10% 0% 12 Fuel prices escalate in real EIPS base EIPS 1 to EIPS 10% As noted. terms 2 over planning window 13 Lower discount rate EIPS base EIPS 1 6% 0% Additional case combinations 14 NCRE forced with fuel price EIPS base EIPS 1 to EIPS 10% As noted. escalation 2 by 2020 and beyond at same rate 15 Pumped storage and DSM EIPS base EIPS 2 10% 0% intervention All cases assumed to be compliant with the present standards (ie, those issued for Puttalam) EIPS base, high = base and high forecasts prepared by the Consultant EIPS 1 = A fuel price scenario based on a crude oil price of 75 USD/bbl in real terms. EIPS 2 = A fuel price scenario based on a crude oil price of 125 USD/bbl, in real terms. Sri Lanka: Environmental Issues in the Power Sector 72 ECA, RMA and ERM Cases 7.2 Reference case results The least-cost reference case plan indicates that, other than some peaking units, coal should be chosen for the future expansion of Sri Lanka’s generating system, with sub- critical candidates chosen prior to 2021 and super critical candidates selected thereafter. Figure 27 shows the capacity additions in the reference case to develop a least cost generating system. If the reference case plan is implemented, by year 2020, the share of coal-fired generation would be 66.3% and will further rise to 82.9% by the end of the planning window in 2028. Figure 27 Capacity additions in the reference case 700 Hydro Combined Cycle Gas turbines Coal Puttalam Coal Trincomalee Other coal subcritical Other coal supercritical 600 New Capacity Added (net MW) 500 400 300 200 100 - 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 Year 2028 The complete year by year capacity additions, energy dispatches from each power plant and the fuel consumption, are given in Annex A10. The choice of the plants for the base-load is not affected by the sensitivity analyses. In each policy scenario and sensitivity study, depending on the forced conditions, the commissioning dates for the base load plants and the number of power plants are shifted to suit the system requirements. Thus, except in the LNG forced case and the case of no-coal beyond the currently committed plants, the long-term base load solution for the expansion of the power generating system in Sri Lanka is coal-fired generating technology. Concerns, however, could be raised over two issues: (i) the dominance of coal in the fuel mix of the generating system, rising from 18% in 2011 to 86% by 2028, which causes concern on energy security (see Table 33; and Sri Lanka: Environmental Issues in the Power Sector 73 ECA, RMA and ERM Cases (ii) the part-load operation of coal-fired power plants, especially after the year 2020 (see Figure 28)65, although improvements can be made by changing the load shape through techniques such as DSM and pumped storage power plants. We have addressed the issue of the decrease in fuel diversity previously, and the possibility of DSM and pumped storage power plants assisting by improving the utilisation of base load power plants is examined in later cases. Table 33 Energy share of each generating technology 2010 2015 2020 2025 Hydro 40.9% 29.2% 20.0% 14.4% NCRE 4.4% 2.9% 2.0% 1.4% Oil 54.7% 8.7% 2.3% 0.2% Coal 0.0% 59.2% 75.7% 84.0% Figure 28 Concerns about lower capacity factor of baseload power plants 100% 90% 80% 70% Group capacity factor 60% 50% 40% Coal Puttalam 30% Coal Trinco 20% 10% Other coal supercritical 0% 2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 65 The model prefers to build more coal-fired power plants based on their economic merit, but when the supercritical power plants are absorbed into the least cost plan the utilisation of the older plants at Puttalam and Trincomalee would reduce. Sri Lanka: Environmental Issues in the Power Sector 74 ECA, RMA and ERM Cases 7.3 LNG power plants LNG power plants were not selected to be in the least-cost solution, but were required to be forced-in in order to examine the cost implications of a LNG-favoured scenario (case 2). In case 7 where no coal power plants were allowed beyond the present commitments (3x900 MW at Puttalam and 2x250 MW at Trincomalee), LNG was selected to be in the least cost solution. 7.4 Medium-scale hydropower plants The model did not select medium-scale hydropower plants from the candidate plant list at the 10% discount rate in the reference case. In case 3, we have forced these power plants into the model, but they were automatically selected into the least cost solution when the discount rate was lowered to 6% (sensitivity case 13). 7.5 Pumped storage option The model selected all the four units of the pumped storage power plant commencing from 2025 (although they were allowed to be selected from 2020 onwards). Table 34 shows the impact on the least cost plan for each type of power plant. The overall capacity saving at the end of the planning window is small (62 MW). Figure 29 shows the capacity factor improvements of the two power plant groups which were of concern. Table 34 Capacity displaced by pumped storage generation Difference in capacity between the Reference Case and the Pumped Storage Case (MW) Type of power plant 2025 2026 2027 2028 Cumulative Gas turbine capacity saved -35 208 173 277 277 Subcritical coal capacity saved 0 0 0 285 285 Supercritical coal capacity saved 552 0 552 0 0 Pumped storage capacity (added) 250 250 500 500 500 Sri Lanka: Environmental Issues in the Power Sector 75 ECA, RMA and ERM Cases Figure 29 Improved loading of baseload power plants with pumped storage 100% 90% 80% 70% Group capacity factor 60% 50% 40% Coal Puttalam 30% Coal Trinco 20% Other coal supercritical Coal Puttalan (with PS) 10% Coal Trinco (with PS) 0% 2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 7.6 DSM intervention The key drivers of the DSM scenario, as explained in Section 5.10 above, is further popularization of CFLs, and phasing out CFLs to reach a complete ban of incandescent bulbs in households by the year 2013. The average household presently has three CFLs and four incandescent bulbs, and it was assumed that the incandescent bulbs will be replaced with CFLs over time as the incandescent bulbs burn out. The number of incandescent bulbs and the number assumed to be switched on at peak times is assumed as shown in Table 35. Table 35 Assumptions on the use of incandescent bulbs Year No. of incandescent bulbs per household (in DSM case) No. of bulbs owned No. of bulbs switched on at peak 2009 4 2 2010 3 1 2011 2 0 2012 1 0 2013 0 0 2014 0 0 Savings in each time interval within a day were then developed, and the peak demand and energy savings was estimated for each year, as summarised below. Sri Lanka: Environmental Issues in the Power Sector 76 ECA, RMA and ERM Cases Table 36 Estimated savings in energy 2010 2015 2020 2025 Percentage reduction in energy (average day) Day 04:30 to 18:30 0.86% 2.68% 2.10% 1.35% Evening 18:30 to 22:30 4.96% 15.43% 12.04% 7.83% Night 22:30 to 04:30 1.18% 3.74% 2.81% 2.06% Reduction in daily energy (MWh) Day 04:30 to 18:30 266 794 896 803 Evening 18:30 to 22:30 599 1,750 1,965 1,782 Night 22:30 to 04:30 133 324 346 355 Total 998 2,868 3,207 2,940 The load forecast was then revised accordingly, as shown in Table 37. Table 37 Load forecast in the DSM case 2009 2010 2015 2020 2025 EIPS reference case Peak (MW) 1,949 2,136 3,242 4,667 6,432 Energy (GWh) 9,764 10,720 16,472 23,997 33,469 Load factor 57.2% 57.3% 58.0% 58.7% 59.4% DSM case Peak (MW) 1,949 2,012 2,939 4,334 6,091 Energy (GWh) 9,764 10,608 15,919 23,390 32,847 Load factor 57.2% 60.2% 61.8% 61.6% 61.6% The reduction in peak demand is a direct input to WASP model, and the change in load shape was modelled by altering the load-duration curve input to WASP such that the resulting load factor matches the forecast load factor. As the peak demand is reduced, the investments in capacity were consequently lower in the DSM case, mostly displacing open-cycle combustion turbines. Sri Lanka: Environmental Issues in the Power Sector 77 ECA, RMA and ERM Cases 7.7 Non-conventional renewable energy 7.7.1 Economic costs of NCRE The feed-in tariffs offered for NCRE are financial costs, and for the analysis in this study, the financial feed-in tariffs are converted into economic costs. The levelised financial costs to be paid each year over 20 years were converted into an economic cost using a standard conversion factor and then the real discount rate was used to calculate the levelised costs. The results are shown in Table 38. Table 38 Estimated economic costs of present NCRE Tariffs Evaluation Economic costs (b) Capital cost Maintenance Contract Levelised Fuel cost Plant (million cost period cost (LKR/kWh) factor Technology LKR/MW) (LKR m/y) (y) (LKR/kWh) Mini-hydro 190 4.28 - 42% 20 9.75 Wind 230 5.18 - 32% 20 15.31 Biomass 217 6.51 5.36 80% 20 14.32 Agro & Indus 217 6.51 2.67 80% 20 10.30 Municipal Waste 313 16.43 - 80% 20 10.91 Waste Heat 217 2.16 - 67% 20 6.23 Notes: Standard conversion factor = 0.75; discount rate = 10%. The comparison of these economic costs with those of candidate power plants is shown in Table 39. The analysis indicates that when NCRE prices are converted to economic costs, they would not be economical when compared with coal under both scenarios. Sri Lanka: Environmental Issues in the Power Sector 78 ECA, RMA and ERM Cases Table 39 Estimated economic costs of NCRE and candidate plants in the study Levelised cost (US cents/kWh) Conventional Technology Non-Conventional Renewable Energy EIPS1 EIPS2 CGT 35 22.49 36.89 Wind 13.31 CGT 75 21.25 34.98 Biomass 12.45 CGT 105 21.02 34.75 Municipal Waste 9.48 CC DSL 14.08 22.67 Agro & Indus 8.96 CC HFO 11.15 17.35 Mini-hydro 8.48 CC LNG 8.67 13.49 Waste Heat 5.42 COL Sub 6.40 8.87 COL Sup 6.19 8.44 7.7.2 Economic value of NCRE A further comparison of the economic value of NCRE can be calculated using case 4 of this study, in which the costs of NCRE were not included in the analysis, but NCRE was forced into the plan to ensure that the 10% target is met by year 2015 (and sustained thereafter). As seen in Table 40 the generating system (under the EIPS1 fuel price scenario) would be economical if the economic cost of NCRE is below 9.32 UScts/kWh. It should be noted that all economic costs estimated for on-going NCRE developments (Table 40), except waste heat recovery for which there are no power plants as of now, are higher than the breakeven economic value of 7.17 UScts/kWh calculated in this study. Therefore, we conclude that the present prices offered to NCRE cannot be justified on the basis of system least cost, under the EIPS1 fuel price scenario. Sri Lanka: Environmental Issues in the Power Sector 79 ECA, RMA and ERM Cases Table 40 Economic Benefits of NCRE Present Value Energy Benefit, GWh Cost of the Case, $ million Non-NCRE NCRE Case 1 – Reference case with existing NCRE 9,228 150,945 4,000 Case 2 - NCRE forced to meet 2015 target and 9,926 141,216 13,729 beyond Incremental for NCRE 697 9,729 Economic value of NCRE = 7.17 US Cents/kWh 7.8 Other observations A significant feature of the reference case plan is that the operating costs (fuel + variable O&M) continue to decline through the planning window. The present costs are assessed to be 6.33 UScts/kWh generated (excluding the adjustment for payments to NCRE) and it is estimated that they would decline to 3.88 UScts/kWh by the end of the planning window – a drop of about 39%. More important is the decline in the costs per kWh generated from thermal power plants, which decline from 11.47 to 4.35 UScts/kWh, a significant drop of 62%. Figure 30 Economic costs of policy options 14 Cost per thermal kWh generated 12 Cost per kWh generated Specific Operating Cost (UScts/kWh) 10 8 6 4 2 0 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 Sri Lanka: Environmental Issues in the Power Sector 80 ECA, RMA and ERM Multi-attribute assessment 8 Multi-attribute assessment The discussion of the previous section is in terms of the traditional economic analysis criterion - system net present value and the levelised cost per kWh. But as noted in Section 1.3, other objectives not captured in this criterion – energy security, environmental concerns, consumer tariff impacts – are receiving increasing attention, notably the question of GHG emissions. The attributes assessed in this section are: economic efficiency: system net present value (as described and discussed in the previous section) climate change: undiscounted lifetime CO2 emissions tariff indicator: levelised average tariff (equal to the present value of revenue requirements divided by the PV of energy sold) local air pollution impacts: population and stack height-weighted SO2 emissions. energy security: Herfindahl index of generation mix (an index used in economics to measure the concentration of firms in an industry): H = ∑si2 n where si is the share of generation from the i-th supply source (the lower the value of H, the greater is the diversity of supply). 8.1 The reference case 8.1.1 CO2 emissions In the reference case, CO2 emissions increase ten-fold, a direct consequence of the increase in coal generation, which by 2025 accounts for 86% of energy (Figure 31). Figure 31 Reference case generation and CO2 emissions Sri Lanka: Environmental Issues in the Power Sector 81 ECA, RMA and ERM Multi-attribute assessment But this increase starts from a very low level, so when measured in per capita terms, the increase is from 0.18 tonnes/capita to 1.26 tonnes/capita. Even if this were doubled to take into account non-power generation emissions, compared to emissions in the rest of the world, even a tenfold increase barely registers in global comparisons. If China (4.6 tonnes/capita) and the US (19 tonnes/capita) were to dramatically lower their emissions from present levels as part of the current efforts to negotiate a post- Kyoto treaty, Sri Lanka’s 2028 emissions would still be an order of magnitude lower (Figure 32). Other examples in 2007 include India (1.2 tonnes per capita), Brazil (1.8 tonnes per capita) and Vietnam (1.2 tonnes per capita). Figure 32 Per capita GHG emissions 8.1.2 Local air emissions As shown in Figure 33, total SO2 emissions will almost double over the planning horizon. Emissions from heavy fuel oil projects decrease as these are retired, but this decrease is more than offset by coal emissions – though the rate of growth declines after 2021 as an increasing proportion of generation is in the more efficient super- critical units. Sri Lanka: Environmental Issues in the Power Sector 82 ECA, RMA and ERM Multi-attribute assessment Figure 33 SO2 emissions, reference case But as noted earlier, tonnes of SO2 is not a meaningful scale of measurement, for it bears little relationship to likely impacts on local air quality. As soon as emissions are weighted by population, and adjusted for stack height66, the picture changes significantly – as shown in Figure 34A. At present the bulk of SO2 emissions are produced from plants burning heavy fuel oil with low stacks, no FGD controls, and located predominantly in the most heavily populated Western Province. As the Puttalam units, with 160 meter high stacks, located in a less densely populated area, and fitted with FGD, enter service, the capacity factor at the Asia Power plant declines from 75% to 4% and the Kerawalapitiya plant factor declines from 77% to 12%. Beyond 2020, there is a shift of coal-fired plants to the east coast, with a yet lower population density and an almost complete phasing out of generation at the residual oil plant at Sapugaskanda in the Western Province. Figure 34 SO2 emission damage A. Population and stack height weighted index B. Monetary damage costs, $USmillion The damage costs for particulates follow an almost identical pattern of variation across time (Figure 35). The scale of the population weighted index is to some extent 66The stack height weighting is consistent with the damage costs for SO2 shown in Table 10, namely $6/tonne for tall stacks, $33/tonne for medium height stacks. Sri Lanka: Environmental Issues in the Power Sector 83 ECA, RMA and ERM Multi-attribute assessment arbitrary, but the purpose of the index is to give an indication of relative impacts, independent of any monetisation. The emissions and damage cost attributes for NOx show much the same pattern as particulates shown in Figure 35. Figure 35 Damage costs for particulates A. Population and stack height weighted index B. Monetary damage costs, $USmillion The index values cannot of course be added or compared across pollutants (since they have different unit dimensions). However, when monetised, by far the largest contribution to the total damage cost is from SO2, as shown in Figure 36A. However, when compared to GHG emissions at $30/tonne CO2, local environmental damage costs are very small compared to potential GHG damage costs (Figure 36B)67. Figure 36 Comparison of damage costs A. Local air emission damage costs B. Local versus global damage costs 8.1.3 Energy security Figure 37 shows the generation shares used in the supply diversity attribute. Note the inexorable increase in coal share, rising from the present zero to 59% by 2015, and 86% by 2028. 67 Of course, were the much higher EXTERN-e values used for this comparison, the result would be different. But even if the World Bank damage cost estimates were an order of magnitude too small, GHG emissions would still account for a much greater share of the total. Sri Lanka: Environmental Issues in the Power Sector 84 ECA, RMA and ERM Multi-attribute assessment Figure 37 Generation shares, reference case The supply diversity index rises in the early years as the coal share increases, with the greater diversity reached in 2015. But as the coal share rises further, to dominate the picture by the end of the planning horizon, diversity decreases (Figure 38). Clearly, with 86% of generation in one technology/fuel, diversity is smaller than the present situation, where two fuels dominate (oil and hydro). Figure 38 Supply diversity index, reference case Figure 38 also shows the diversity index based on capacity, which is more diverse (lower index value) than energy diversity, because hydro has a larger share in capacity than it does in energy (as does remaining oil capacity once coal takes over base-load). In principle, water in storage reservoirs could be released in case of a fossil fuel supply disruption - and acts in the same manner as a strategic oil reserve in storage tanks. But unlike oil (or coal stockpiles), which can easily be replenished once a supply disruption is over, refilling hydro reservoirs occurs at nature’s pace, not that of a commodity buyer. This decrease in diversity can be mitigated by the introduction of an additional fuel (LNG), or by a significant increase in the renewable share. Figure 39 shows the Sri Lanka: Environmental Issues in the Power Sector 85 ECA, RMA and ERM Multi-attribute assessment generation mix in the LNG scenario, with the result that by 2020, no technology has a share greater than 40%. Figure 39 Impact of LNG on the generation mix But as more and more LNG units are built, LNG assumes the dominant share and, as in the reference case, the diversity again starts to decrease (Figure 40). Figure 40 Impact of LNG on the capacity diversity index 8.1.4 Tariffs Figure 41 illustrates the revenue requirements in the reference case, expressed as $US million at constant 2009 price levels. This is calculated as the sum of all financial costs incurred by CEB including fuel and O&M costs calculated by the WASP model, debt servicing costs on past investments and on new investments in generation (estimated by the WASP model) and transmission and distribution (T&D), and a reasonable return on investment. Those fixed O&M costs that are not calculated by the WASP model and the T&D investments, are extrapolated from CEB’s historic costs. The revenue requirements are calculated on the assumption that no subsidies are provided to CEB. Sri Lanka: Environmental Issues in the Power Sector 86 ECA, RMA and ERM Multi-attribute assessment Figure 41 Revenue requirements As $ million As percentage share The spike in revenue requirements (and in the average tariff shown in Figure 41), is a consequence of the delay in commissioning of Puttalam units 2 and 3. This delay results in oil burning power plants being used more, with a consequent increase in fuel costs. The share of fuel costs in the total drops from 45% in 2009 to a minimum of 40% in 2016, but thereafter it begins to rise again, reaching 44% by 2020. Though fuel costs decrease in absolute terms, the phasing out of IPP payments result in the fuel share increasing. The retail tariff is calculated as the average revenue requirements per kWh sold. Figure 42A shows the retail tariff trend superimposed on the fuel cost (expressed per kWh of thermal generation), and the renewable energy tariff, expressed per kWh of renewable energy generation). The aggregate tariff reflects the spike in fuel costs in 2013. Figure 42 Tariff trends A. Reference case B. LNG Figure 42B shows the corresponding evolution of tariff in the case of LNG. Despite the lower capital costs, the fuel costs are markedly higher, and the tariff at the end of the planning period rises to 11 UScents/kWh, as against 7.9 UScents/kWh in the reference case. Sri Lanka: Environmental Issues in the Power Sector 87 ECA, RMA and ERM Multi-attribute assessment 8.1.5 Summary of attribute values Table 41 shows the complete list of attribute values for the 15 scenarios examined. Sri Lanka: Environmental Issues in the Power Sector 88 ECA, RMA and ERM Multi-attribute assessment Table 41 Attribute values System NPV H-index Undiscounted Discounted Levelised NPV 2020 Levelised ($ mn.) GHG emissions emissions emission (population tariff tariff (mn. tonnes (mn. tonnes factor weighted SO2) (Rs/kWh) (Rs/kWh) CO2) CO2) (kgCO2/kWh) Reference 9,228 0.56 305 94 0.61 861 8.9 10.3 LNG 10,722 0.38 228 77 0.50 877 10.2 11.8 Hydro 9,348 0.53 295 91 0.59 874 9.0 10.4 NCRE 9,926 0.48 278 86 0.56 825 10.4 11.4 ‘Green’ 11,137 0.34 207 70 0.45 788 11.3 12.2 Forced supercritical 9,246 0.55 295 91 0.59 895 8.1 10.0 No coal 10,199 0.37 227 76 0.49 835 10.2 11.3 Pumped storage 9,204 0.56 306 94 0.61 859 8.9 10.3 DSM 9,179 0.56 298 91 0.60 835 8.8 10.2 High demand 10,732 0.58 354 109 0.63 1084 9.2 10.1 High fuel prices 13,138 0.56 306 94 0.61 860 11.3 13.2 Real price increases 10,859 0.56 305 94 0.61 860 10.4 11.5 Low discount rate 12,325 0.56 299 92 0.60 839 8.9 10.3 NCRE+fuel price 12,867 0.48 281 87 0.56 834 12.8 13.5 escalation Pumped storage+DSM 9,153 0.56 299 92 0.6 838 8.8 10.2 Sri Lanka: Environmental Issues in the Power Sector 89 ECA, RMA and ERM Multi-attribute assessment Several points in Table 41 may be noted: Not all of the scenarios are directly comparable: for example the system cost of the low discount case cannot be compared to the other scenarios – though one can compare differences in the capacity expansion plan and the environmental impacts that follow (see below, Section 8.1.6). The scenarios with higher energy prices appear to have no impact on CO2 emissions. This has two explanations: First, as discussed in Section 3.4, the price elasticity of demand is very low, so passing higher prices onto consumers has no (or very little impact on demand and, therefore, on CO2 emissions).68 Were higher prices to lead to reductions in demand, then there would indeed be a decrease in CO2 emissions. Indeed, in the opposite case of high demand, CO2 emissions increase (as do costs). Second, we assume that the relative fuel prices (of LNG, coal, and petroleum products relative to crude oil) stay unchanged, so that the relative advantage of coal stays unchanged. Even if there were a divergence of relative prices at the higher oil price, the cost advantage of coal over oil and LNG is so great that it would have little impact on the optimal generation mix. 8.1.6 Impact of lower discount rates The impact of the lower discount rate is much as expected: the planning model chooses to build medium scale hydro projects in 2014 and 2015, reducing the need for additional combustion turbine capacity. In the later years of the planning horizon, the model builds additional coal capacity, rather than the combustion turbines built in 2026 and 2028 in the case with the 10% discount rate in the reference case (Figure 43A). Figure 43 Impact of discount rate on generation investment plan A. 10% discount rate B. 8.5% discount rate 68 Because of this low price elasticity, there is no need to rerun the demand forecast and re-run WASP with this lower forecast. Sri Lanka: Environmental Issues in the Power Sector 90 ECA, RMA and ERM Multi-attribute assessment These small changes in the expansion plan have correspondingly small changes in the environmental indicators. Lifetime GHG emissons decline by 6 million tonnes CO2, and the population and stack height weighted SO2 index declines by 2.6% (from 861 in the reference case to 839) as a consequence of the additional hydro in the low discount rate case. 8.2 Trade-off curves 8.2.1 GHG emissions With the attributes calculated for each scenario, their values can now be plotted as a trade-off plot. Figure 44 shows the plot of system NPV versus discounted CO2 emissions. As expected, the scenarios involving additional renewable energy and LNG (which is a part of the No-coal, Green and LNG scenarios) are in the trade-off quadrant-IV– lower CO2 emissions can only be achieved at (significantly) higher cost. Figure 44 Discounted CO2 emissions versus present value costs Note: The diagram shows only emissions from combustion. Also as expected, DSM is in the win-win quadrant, while pumped storage (PS) is in the trade-off quadrant-II – system costs are lower, but greenhouse gas emissions are higher. In other words, from the perspective of Sri Lanka, pumped storage is a desirable option and should be included in CEB’s least cost plan (always assuming that the detailed feasibility studies confirm the costs assumed in the preliminary study that is the basis of our initial assessment). Forcing in supercritical coal-fired power plants before they would otherwise be selected and the implementation of the medium hydro projects are also both in the trade-off quadrant-IV. The corresponding carbon shadow prices are shown in Figure 45. The interpretation of a negative value (as for DSM, and any other option in the win-win quadrant) is that for every tonne of CO2 reduced, there is a benefit of $20; the interpretation of the value shown for pumped storage – for which cost decreases and carbon increases - is that for every tonne of increased CO2 there is a benefit of $120 in reduced costs. Sri Lanka: Environmental Issues in the Power Sector 91 ECA, RMA and ERM Multi-attribute assessment Figure 45 shows the carbon shadow prices for the CO2-avoiding options. That of the medium-sized hydro projects (apart from super-critical coal-fired technology) is by far the lowest at $37/tonne, and is the only one that corresponds to the carbon price current observed in global carbon markets.69 Figure 45 Carbon shadow prices (combustion emissions only) As shown in Figure 46, there is little difference in the shape of the trade-off curves and the relative positions of the options when undiscounted lifetime GHG emissions are used. Figure 46 Undiscounted lifetime GHG emissions versus present value system costs However, when lifecycle GHG emissions are considered (rather than just combustion emissions), some more significant changes occur – apart from the obvious increase in emissions themselves. As shown in Figure 47, for those options in the trade-off quadrant-IV that involve LNG, the carbon shadow price increases (because the GHG 69 World Bank, State and Trends of the Carbon Market 2009, May 2009. In 2008, the average transaction cost in the largest carbon market, the EU ETS, increased from $21.25/tonne of CO2 in 2007 to $26.25 per tonne of CO2 in 2008. The 2008 average price in the primary CDM market was $16.76/tonne of CO2. Sri Lanka: Environmental Issues in the Power Sector 92 ECA, RMA and ERM Multi-attribute assessment emission advantage over coal is much less than if only the combustion impact is considered). For the other options, such as renewables, hydro, and DSM, the shadow price decreases, because all fossil fuel emissions increase (even in the absence of LNG), and so the avoided carbon benefit of these options is correspondingly greater. Figure 47 Carbon shadow prices (lifecycle emissions) The important conclusion from this is that the GHG emission benefit of LNG over coal is much smaller when lifecycle emissions are included in the comparisons. Table 42 below shows the complete set of results for emissions and shadow prices. These differences are also reflected in the system emission factors (as kgCO2/kWh) as used in CDM calculations – values that determine the number of carbon credits achievable – the higher the emission factor, the greater is the value to a small renewable energy producer seeking revenues from carbon emission reduction credits. As shown in Figure 48, the 2009 value of the emission factor is a relatively low at 0.38, but this increases over time (in the reference case) as the proportion of coal in the system increases. Although lifetime emissions are not used in the CDM calculations, even when only combustion emissions are considered, the emission factor reaches 0.75 kg CO2/kWh. Figure 48 System emission factors, kgCO2/kWh Sri Lanka: Environmental Issues in the Power Sector 93 ECA, RMA and ERM Multi-attribute assessment Table 42 Comparison of GHG emissions from combustion against lifecycle emissions Discounted emissions Undiscounted GHG emissions Carbon ‘shadow’ price (million tonnes CO2) (million tonnes of CO2) ($/tonne of CO2) Scenario Comb- Lifecycle Difference Comb- Lifecycle Difference Comb- Lifecycle Difference ustion ustion ustion Reference 94 102 9 305 334 29 LNG 77 87 11 228 267 38 86 98 11 Hydro 91 99 8 295 323 28 37 34 -4 NCRE 86 94 8 278 304 27 87 80 -7 ‘Green’ 70 79 9 207 240 33 79 81 2 Forced supercritical 91 99 8 295 323 28 7 6 -1 No coal 76 86 11 227 265 39 53 61 7 Pumped storage 94 103 9 306 336 29 104 104 0 DSM 91 100 8 298 326 29 -20 -18 2 Pumped storage+DSM 92 100 8 299 328 29 -33 -31 3 Sri Lanka: Environmental Issues in the Power Sector 94 ECA, RMA and ERM Multi-attribute assessment LNG will of course reduce this emission factor – from a maximum in 2015-2016 back to 0.6 kgCO2 /kWh by 2028. The irony here is that as the emission factor declines as a result of large LNG plants replacing coal, the avoided emissions, and hence also the carbon revenues, from small renewable energy producers will decline 8.2.2 Supply diversity The tradeoffs between system cost and average energy security are shown in Figure 49. The general pattern corresponds to the trade-offs between cost and GHG emissions, though pumped storage now lies in the win-win quadrant rather than the trade-off quadrant-II. Indeed, all options improve generation diversity over the reference case. The ‘Green’ scenario (LNG + medium hydro + NCRE (small renewables)) has the highest generation mix diversity. Figure 49 Energy security index versus system cost 8.2.3 Local air emissions The trade-off plot for cost versus population and stack height weighted index of SO2 emissions is shown in Figure 50. Notably, pumped storage is in the win-win quadrant and hydro, LNG, and forcing-in supercritical coal-fired plants (sooner than the reference would provide by itself) are unexpectedly in the lose-lose quadrant – with higher costs and higher impacts. The explanation relates primarily to the location of the energy production and the implications for local populations. In the case of the pumped storage option, the move into the lose-lose quadrant is because pumping energy is provided by Trincomalee coal plants located in the less populated east and this displaces energy from gas turbines in the highly populated and relatively wealthy Western Province. Even though SO2 emissions are greater from coal with the pumped storage option, this is more than offset by the location and stack height effects resulting in an improved air quality index. Sri Lanka: Environmental Issues in the Power Sector 95 ECA, RMA and ERM Multi-attribute assessment Figure 50 Trade-off between population and stack-weighted SO2 and system cost To understand why hydro is in the lose-lose quadrant in Figure 50, one needs first to understand how the expansion plan has changed. The hydro projects delay two 300 MW Trincomalee coal units. These two units have relatively low population-weighted emissions, and their delay results in the dispatch of more fuel-oil burning plants, with short stacks, located in the densely populated west. Even though the total quantity of fuel decreases with the hydropower projects in the mix, this is not enough to offset the shift to more damaging emissions in the west. In the case of supercritical coal-fired plants (commissioned earlier than would otherwise be chosen by the least-cost planning model), this also leads to increased production from the oil-fired plants in the densely populated west, and worsening of the air quality index. This increased production of the oil-fired plants is likely because of the large size of the supercritical units relative to the system maximum demand, leading to the greater use of the smaller and more flexible oil-fired plants. The poorer air quality in the LNG case in Figure 50 arises because the LNG plants are assumed to have a higher variable fuel cost than some of the oil-fired plants, leading to greater operating hours of oil-fired plants and increased emissions in the densely populated west. In reality, the LNG plants would have take-of-pay obligations which would mean that the LNG plants would be operated ahead of oil-fired plants in the merit order and local air quality would be better. However, the cost attribute for LNG would then be even worse than that shown in Figure 50. If LNG plants do have take- or-pay obligations then the LNG case would probably sit in the trade-off quadrant IV with higher costs and a slightly improved air quality index. 8.3 Conclusions of the multi-attribute analysis This analysis permits the following conclusions: Increased coal will lead to a significant increase in CO2 emissions. This underscores the importance of adopting super-critical technology as soon as the size of the system permits it. We recommend that in CEB’s future Sri Lanka: Environmental Issues in the Power Sector 96 ECA, RMA and ERM Multi-attribute assessment generation planning studies, supercritical units be included as an option: relative to subcritical units - super-critical is win-win. It should be noted that in terms of emissions per capita the increase in CO2 emissions attributable to power generation is small compared to global averages. The assessment of carbon shadow prices shows that, among the supply side options, completing the four medium sized hydropower plants is the most cost effective way of reducing CO2 emissions, with a carbon shadow price at the level of global carbon market prices. It makes little sense to implement LNG (or even wind and biomass that is part of the NCRE scenario) if one does not first implement much cheaper ways of achieving the same objective. Further support in favour of developing the medium sized hydro projects is that they are only justified at a discount rate below the reference discount rate. Since they are not in the least cost plan at the Government established discount rate, they will be considered ‘additional’ under CDM rules, and stand a reasonable chance of attracting carbon finance. LNG is the least attractive of the clean energy options. With a carbon shadow price slightly higher than that of the NCRE scenario, and with a similar diversity benefit, NCRE would be preferred to LNG. Additionally, LNG has significant upside risk (if oil prices are 150$/bbl rather than $75/bbl, the LNG shadow price will be significantly higher than that of NCRE (which carries no fossil fuel price or volatility risk). The LNG option also has a corresponding impact on tariffs, with a tariff at the end of the planning horizon some 3 US cents/kWh higher than in the reference case. DSM is win-win, as is the combination of DSM and pumped storage. In any event, pumped storage slightly lowers system cost, and therefore CEB should proceed with more detailed studies to verify the costs of the preliminary assessments prepared by JICA. Examination of the population and stack-height weighted SO2 emissions shows the importance about not coming to simple conclusions about environmental damage costs that are based simply on aggregate emissions. We see, for example, that although hydro projects produce no GHG emissions, SO2 damage costs may yet be higher if changes in the capacity expansion plan results in greater dispatch from other projects that are located in more densely populated areas. Sri Lanka: Environmental Issues in the Power Sector 97 ECA, RMA and ERM Implications for Decision Makers 9 Implications for Decision Makers Sri Lanka is faced with the choice of continuing with current, controversial plans to build coal-fired power plants, or to follow a greener path. The analysis provides decision makers with information that allows choices to be made from the alternative paths. We consider five main measures of impact: economic cost GHG emissions local environmental impact energy security and tariffs If cost is the only consideration, the reference case marked by coal as the dominant expansion technology (by 2025, coal will account for 84% of generation) would be the clear winner. Only the two cases that include DSM show lower total system costs. The analysis suggests that irrespective of environmental considerations, further DSM programmes should be explored further as a way to reduce costs. Yet, system cost is not the only consideration, as evidenced by Sri Lanka’s efforts to enact environmental standards which limit emissions. This concern is important because the analysis indicates that the reference case, involving coal-fired plants, does not lead to significant increases in local environmental impacts. Indeed, while increased use of coal for power generation in Sri Lanka will lead to a significant increase in SO2 emissions, the stack height and population weighted emissions are lower than those produced by the oil-fired plants today. Likewise, while an even more dramatic rise will occur for CO2 emissions (a ten-fold increase relative to a four-fold increase for SO2 emissions), the increase on a per capita basis means Sri Lanka’s 2028 emissions would be an order of magnitude lower than per capita emissions in the United States – this ten-fold increase barely registers when compared to the remainder of the world. Despite the absence of significant environmental impacts compared with environmental impacts from the current plant mix, should additional reductions be desired, the analysis does show that these could be achieved through specific polices such as higher targets for non-conventional renewable resources. Yet, implementation of these policies will come at a cost. Of course, there may be ways to finance these costs without impacting consumers or the national budget - if CO2 certified emission reduction certificates are valued at more than $37/tonne then this would be financially attractive for Sri Lanka70. However, latest projections suggest that CO2 is unlikely to be 70Care must also be taken to ensure that it is clear to UNFCCC that Sri Lanka assumed the availability of CERs when approving policies – otherwise UNFCCC may assume that these policies are part of Sri Lanka’s baseline. Sri Lanka: Environmental Issues in the Power Sector 98 ECA, RMA and ERM Implications for Decision Makers valued at the level that, by itself, would merit investment in some of the more expensive NCRE71 options and LNG in order to reduce CO2 emissions still further. Sri Lanka’s decision makers would therefore need to take into account other benefits when considering these policies. Importantly, should it be determined that there is a willingness to pay for reducing the impact on the environment and/or improving security of supply, the results show clearly that it makes little sense to implement LNG or even wind and biomass (that are part of the NCRE scenario) if one does not first implement much cheaper ways of achieving the same objective – medium sized hydropower as well as small hydropower (included in the NCRE scenario). Specifically, commissioning of Uma Oya (150 MW), Broadlands (35 MW), Moragolla (27 MW) and Ging Ganga (49 MW) from 2014-2015, despite coal being a cheaper alternative, increases costs by just 0.9% while reducing total CO2 emissions by just under 5%. This would add only 1% to levelised average tariffs compared with the reference case, but even this could be avoided if CDM credits are secured. Moreover, these plants would in any case be chosen as least-cost if a lower discount rate is adopted. A similar result arises when NCRE is forced into the model such that its contribution is 10% of the total energy dispatched from the generating system by year 2015, and sustained at the 10% level until the end of the plan with a matching NCRE injection every year even after 2015. Total system costs increase by approximately 8% while total CO2 emissions decline by just under 10%. Diversity and local air quality likewise improve, creating a win-win outcome in terms of environmental benefits and increased security of supply. The average levelised tariffs would, however, need to rise by approximately 8% relative to the reference case to cover the additional costs to meet this target (though tariffs would not have to increase relative to 2009 levels). Equivalently, GoSL would a subsidy of $82 million per year would need to be found in order to keep electricity tariffs at the level of the reference case. Among the supply side options, the analysis shows that completing the four medium sized hydropower plants is the most cost effective way of reducing CO2 emissions, with a carbon shadow price of $37/tonne of CO2. This is currently at the approximate level of recent global carbon market prices for carbon emission reduction under CDM. The next “cheapest� option has a carbon shadow price of nearly double that of the four hydropower plants (though some NCRE options would certainly have lower carbon shadow prices). As for the continued interest in LNG, this is not the most attractive way to lower CO2 emissions. LNG has a carbon shadow price that is similar to that of the NCRE scenario and has a similar diversity benefit. However, LNG also has significant upside risk if oil prices rise whereas NCRE carries no fossil fuel price or volatility risk. Likewise, as discussed earlier, to benefit from the economies of scale of LNG, it is clear that a project of economic size in Sri Lanka would require substantial non-power gas use. However, unlike other countries in South Asia that already have a gas pipeline and distribution 71The benefits of CDM credits would also flow differently for NCRE and LNG. While the benefits would mostly accrue to Sri Lanka, in the case of NCRE the benefits of CDM credits would, with the current feed- in tariffs, be retained by the developers while for LNG the credits could be used to lower the cost of the project for the benefit of electricity consumers. Sri Lanka: Environmental Issues in the Power Sector 99 ECA, RMA and ERM Implications for Decision Makers system, huge investments would be required to establish a new system. Sri Lanka also lacks large energy-intensive industries that could easily switch from oil to gas were the latter to become available. If, as is likely, Sri Lanka continues to invest in coal-fired power plants then, relative to sub-critical coal-fired power plants, super-critical is win-win. Super-critical technology should be adopted as soon as the size of the power system permits. A pumped-storage scheme is shown by the analysis to slightly lower the total system costs. This suggests that CEB should proceed with more detailed studies to verify the costs of the preliminary assessments prepared by JICA and at that time update the trade-off analysis and make a decision on this investment. Sri Lanka: Environmental Issues in the Power Sector 100 ECA, RMA and ERM Annexes Annexes A1 Review of the past two decades A1.1 Demand growth, customers and prices Until the mid-1990s, the largest share of electricity generation was from hydropower. With most of the major hydroelectric potential now developed, non-hydro sources were required to meet the growing demand for electricity. In 2008, only 42%72 of the total electricity demand was met with hydroelectric power plants (both large and small), compared with 94% in 1995. Electricity sales have increased from 2,394 GWh in 1990 to 8,349 GWh in 200873 as shown in Figure 51. Peak demand in 2008 was 1,922 MW. The electrification level of the households increased from 29% in 1990 to about 85% in 200974. Figure 51 Historic growth in sales (grid) 9,000 8,000 Electricity Sales (GWh) 7,000 6,000 5,000 4,000 3,000 2,000 1,000 0 1990 1992 1994 1996 1998 2000 2002 2004 2006 2008 Year Source: Consultant’s diagram using information in CEB Statistical Digests 1990-2008 There were severe capacity shortages in the generating system in the period 1996-97 and again in 2000-02, which led to rolling blackouts extending up to eight hours a day. In other years, with unconstrained supply, the demand growth has been high, but from 2006 the growth levels have declined. The sales growth in 2008 was 4%. In 2009, 72 It is calculated in the gross generation terms. 73 Total sales to end-use customers. This includes the sales of LECO which amounts to 12.7% of the total. 74 However, the high number of zero-consumption households reported by CEB is a concern, which was 3.2%, 5.7% and 5.8% in years 2002, 2005 and 2006. CEB maintains that these are households that have an active electricity connection but do not consume owing to the occupants being away. The actual number of households with an active electricity connection is likely to be lower than the published statistics. Sri Lanka: Environmental Issues in the Power Sector 101 ECA, RMA and ERM Review of the past two decades generation information available until October 2009 indicates a demand reduction of about 1.3% compared with the same period in 2008. Figure 52 Sales growth rate 14% 12% 10% Annual Growth in Sales ) 8% 6% 4% 2% 0% 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 -2% -4% Source: Consultant’s diagram using information in CEB Statistical Digest in the relevant years Table 43 Historic growth of electricity sales and peak demand Year Total System peak Year Total System peak electricity demand electricity demand sales (GWh) (MW) sales (GWh) (MW) 1990 2,197 640 2000 5,188 1,405 1991 2,448 685 2001 5,178 1,444 1992 2,687 742 2002 5,454 1,422 1993 3,155 812 2003 6,160 1,516 1994 3,427 910 2004 6,598 1,563 1995 3,761 980 2005 7,201 1,748 1996 3,552 968 2006 7,766 1,893 1997 3,971 1,037 2007 8,231 1,842 1998 4,460 1,137 2008 8,349 1,922 1999 4,754 1,291 Source: Sri Lanka Energy System Information 2007, Sustainable Energy Authority, 2007; Statistical Digest 2008, CEB Sri Lanka: Environmental Issues in the Power Sector 102 ECA, RMA and ERM Review of the past two decades The number of household customers of CEB and LECO indicate significant growth, as seen in Table 44, although the high customer growth levels above 10% per year experienced in the 1990s have now declined to moderate growth levels below 10%.75 Table 44 Household customer growth of CEB and LECO Year 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 LECO 159,097 168,416 179,306 191,147 207,505 222,064 233,083 245,246 258,323 270,006 CEB 628,741 751,614 917,319 1,089,287 1,222,124 1,322,087 1,466,815 1,611,102 1,781,388 1,981,691 Total 787,838 920,030 1,096,625 1,280,434 1,429,629 1,544,151 1,699,898 1,856,348 2,039,711 2,251,697 Growth 16.8% 19.2% 16.8% 11.7% 8.0% 10.1% 9.2% 9.9% 10.4% Year 2000 2001 2002 2003 2004 2005 2006 2007 2008 CEB 2,191,301 2,364,853 2,491,349 2,648,968 2,823,654 2,988,223 3,203,049 3,866,950 4,088,900 LECO 284,056 307,582 310,607 329,329 341,016 351,924 360,324 434,247 450,000 Total 2,475,357 2,672,435 2,801,956 2,978,297 3,164,670 3,340,147 3,563,373 4,301,197 4,538,900 Growth 9.9% 8.0% 4.8% 6.3% 6.3% 5.5% 6.7% 5.70% 5.23% Source: CEB. A1.2 Electricity tariffs The average price of electricity continued to increase over the last decade. Sri Lanka’s tariff is high compared with other countries in the region mainly owing to the dominance of the oil-fired power plants and the series of delays in implementing the cheaper power generating options – namely coal and large hydropower. More analyses of prices are presented later in this section. CEB has not been able to finance all its costs even with the increases of electricity prices shown Table 45, and CEB has been directly (such as through direct grants, rescheduling debts due from CEB to the government) or indirectly (paying fuel bills, converting debt to equity) subsidised by the government from time to time. 75 Most of the major rural electrification projects were implemented in the 1990s, giving rise to high annual growth rates in the number of customers. Sri Lanka: Environmental Issues in the Power Sector 103 ECA, RMA and ERM Review of the past two decades Table 45 Historic data on average CEB selling price Year LKR/kWh US Cents/kWh Year LKR/kWh US Cents/kWh 1991 2.40 5.63 2000 4.53 5.66 1992 2.76 6.01 2001 5.48 5.88 1993 3.13 6.31 2002 7.25 7.49 1994 3.76 7.52 2003 7.68 7.96 1995 3.70 6.85 2004 7.66 7.52 1996 4.02 7.08 2005 7.71 7.67 1997 4.15 6.78 2006 8.99 8.65 1998 4.46 6.58 2007 10.56 9.55 1999 4.43 6.14 2008 13.18 12.16 Source: Sri Lanka Energy System Information 2007 Sustainable Energy Authority,2007, Statistical Digest 2008, CEB. Note: Information stated is in current terms. A1.3 Implementation of long-term plans CEB prepares and publishes a least-cost long-term generation expansion plan every year. The year 1992 marks the first policy decision of the Government to invite offers for thermal IPPs based on the BOT/BOO concept. This year is useful as a reference year to examine the implementation status of long-term plans. CEB studies reported in 1992 had a planning window of 15 years76 up to 2007. The studies concluded that hydropower plants at Broadlands (40 MW), Kukule (70 MW) and Upper Kotmale (123 MW) should be commissioned by January 1997, January 1999 and January 2000, respectively. The CEB planning study also specified the need for new coal-fired power plants located at Trincomalee with a total capacity of 1,050 MW developed in five phases. A few small thermal generating plants proposed in the 1992 plan were to be located in the major load centres in the Western Province and near the oil refinery in Colombo. However, the least cost plan was not implemented. Because of delays in the policy decisions, civil unrest77, public protests due to the environmental concerns and a lack of investor interest, Sri Lanka’s electricity generation has become dominated by oil-fired plants. Between 1992 and the end of 2007, 73% of the new additions to electricity generation were from oil-fired power plants against the forecast of 24% in 1992. 76 CEB’s general practice is to model the generating system for 20 years, develop least-cost plans, but report only the first 15 years of the 20 year least-cost plan. 77Trincomalee was highly subjected to armed conflict and civil unrest in 1990s. CEB’s first attempt of building the 300 MW coal-fired power plant was abandoned in the mid of 1990s, largely due to the inability of securing finance. Sri Lanka: Environmental Issues in the Power Sector 104 ECA, RMA and ERM Review of the past two decades Although it was planned to add several coal-fired power plants, to date Sri Lanka does not have any operational coal power plants. The first coal-first power plant is expected to be commissioned by the end of 2010 in Norochcholai, Puttalam, on the north- western coast. In 1996, GOSL made a policy decision to allow developers to build renewable energy- based power plants below 10 MW78. The program has been further strengthened by the national energy policy of 2007. The Government’s 10-year development plan (2007- 2016) envisages the enhancement of renewable energy development to reach a target of 10% of grid energy to be provided from Non-Conventional Renewable Energy (NCRE) sources by year 2015. Starting in 1996, the small power producers have developed about 150 MW of hydroelectric power plants through to the end of 2008. The 1992 plan did not contain any NCRE power plants, but by end 2007, energy from these non- conventional sources is not insignificant. Figure 53 and Figure 54 show the capacity additions by fuel over 1993-2007, and the generation fuel mix in the year 2007, comparing the least-cost plan of 1992 against what was actually implemented. While the lower-cost major hydro capacity additions have been below the target, coal-fired power generation was not installed at all. NCRE power plants, which, as mentioned above, were not considered in the 1992 plan but which were subsequently promoted as private investments starting in 1996, have contributed 11% to new capacity additions. Their energy contribution, however, remains low at 4%. As these were paid at the “avoided cost of thermal generation�, small power producers would not make any significant impact on CEB’s cost structure. Figure 53 Comparison of Capacity Additions over 1993-2007 (1992 plan and actual) 80% Additions specified in 1992 to achieve least cost 73% Share of new capacity installed over 1993-2007 Actual capacity installed 70% 60% 55% 50% 40% 30% 24% 21% 20% 16% 11% 10% 0% 0% 0% Major Hydro Coal Oil NCRE 78 For more information on the NCRE development programme, please see Section 6.2. Sri Lanka: Environmental Issues in the Power Sector 105 ECA, RMA and ERM Review of the past two decades Figure 54 Comparison of Fuel Mix in Generation in 2007 (1992 plan and actual) 70% 2007 least cost plan specified in 1992 Actual status in 2007 60% 60% Share of generation in 2007 50% 47% 40% 38% 37% 30% 20% 14% 10% 4% 0% 0% 0% Major Hydro Coal Oil NCRE A1.4 Reasons for high generation costs and prices Sri Lanka’s electricity generating costs are observed to be high for two fundamental reasons: The absence of any indigenous fossil fuels and the consequent requirement to import all the fossil fuels at international prices; and CEB’s inability to build large, lower-cost, base load power plants alongside the remaining large hydroelectric power plants, which would have put production costs on par with other countries in Asia. Meanwhile, the demand growth has been met with diesel and fuel-oil burning smaller power plants. The cost of electricity generation of CEB has been high throughout the past 15 years. A1.5 The proliferation of small oil-fired power plants Although not explicitly cited in the above section, the new approach in the mid 1990s to allow private power plants in the grid indirectly caused the lower-cost base load generating projects and new large hydropower projects to be delayed. In response to the solicitations issued to procure Independent Power Plants (IPPs), only oil-fired power plants were offered by the private investors. Oil burning power plants are less capital intensive than coal-burning power plants or hydroelectric power plants, and with fuel costs being a pass-through item in all PPAs, IPPs whether they are on a competitive bid or negotiated, offered only oil-burning power plants. There was at least one bidding round (2002) where a solicitation for 200 MW of capacity was issued without specifying the fuel or the location. However, the delivery time specified was only 15 months, which compelled the bidders to offer oil-burning power plants only. With the generation capacity build-up always lagging behind demand, CEB procured 537 MW of oil-burning IPPs between 1996 and 2007. CEB extended capacity of the Sri Lanka: Environmental Issues in the Power Sector 106 ECA, RMA and ERM Review of the past two decades CEB’s own heavy fuel-fired power plant at Sapugaskanda by 80 MW, built a new diesel-fired gas turbine of 115 MW and built a new diesel/naphtha-fired 165 MW combined cycle power plant. Out of the total of 897 MW of IPP and CEB power plants procured between 1996 and 2007, only 80 MW were included in the 1992 long-term generation expansion plan. Since 2005, however, the projects in the long-term plan are being implemented, based on the national energy policy which imposed a moratorium on oil-fired power plants and placed a firm emphasis on coal and renewables. As mentioned above, the first coal-fired power plant is expected to be operational by the end of 2010. A1.6 Comparison of generation costs The high share of oil-fired thermal generation has resulted in a significant increase in CEB’s fuel bill, as described in Table 46. The fuel cost per kWh generated from thermal power plants has more than doubled as a result of accommodating a large number of oil-fired thermal power plants, in violation of the least cost principles established when long-term plans were prepared. Coupled with the non-implementation of the large hydroelectric power plants in the long-term plan, the severe impacts of the oil-burning power plants on CEB’s operating costs, and thereby the customer prices, is visible in the analysis shown in Table 46. Table 46 CEB’s fuel bill in 2007 (planned in 1992 vs actual) Comparison of fuel consumption and costs (1992 plan for 2007 and actual) Actual year-end Planned Planned fuel Actual Actual fuel price in consumption cost (million consumption fuel cost 2007 (LKR/litre) (thousand LKR) (million litre) (million tonne) LKR) Heavy 75.00 216.9 13,665 466 34,946 diesel Coal 13.05 2,392.0 31,207 - (LKR/kg) Furnace 51.70 - - 513 26,547 oil Residual 45.00 242.0 10,237 296 13,330 oil Naphtha 60.00 138 8,255 Total fuel cost 55,108 83,078 Planned for 2007 in 1992 Actual in 2007 Thermal generation (GWh) 8,091 5,896 Average fuel cost of thermal 6.81 14.09 generation (LKR/kWh) Note: Coal price assumed to be USD 120 per MT delivered to Trincomalee; naphtha prices assumed to be LKR 60 per litre; and exchange rate year end (LKR/kWh) = 108.72. Sri Lanka: Environmental Issues in the Power Sector 107 ECA, RMA and ERM Review of the past two decades The high share of oil-fired thermal generation will continue until the first coal-fired thermal generating plant in Puttalam (Norochcholai) and the Trincomalee coal-fired power plant are added over 2011-2015, and as the Upper Kotmale hydropower project comes online in 2011. Comparisons may also be made on customer prices. The present (2009) estimated average customer price is 12.16 UScts/kWh (ranges from 9.65 for residential to 18.25 UScts/kWh for commercial customers79). A recent (January 2009) comparison among several countries in the region places Sri Lanka not at the highest regional tariff level, but closer to the tariffs of Singapore, as shown in Table 47. The highest tariffs among the countries compared are in Singapore. Sri Lanka, with about 40% of electricity generated using renewable energy (91% of the hydropower comes from medium and large hydropower plants, most of which are depreciated power plants), has higher prices than most of the competitor countries in the region for those reasons described above. Table 47 Comparison of Sri Lanka’s electricity prices with regional countries80 Average unit price of Electricity with unity power factor in each country in USCts/kWh Max. [as of Jan 2009] Elect. Use De- mand Class Maharashtra, Kerala, India Thamilnadu, South Korea Bangladesh Singapore Sri Lanka Malaysia Thailand Pakistan (kWh/ (kW) Nepal month) India India Small 30 - 4.90 2.36 2.39 0.83 6.29 6.58 2.03 20.98 5.12 4.39 4.42 House- Medium 90 - 4.08 3.91 3.11 4.96 6.29 8.47 3.91 20.98 4.50 5.61 5.58 hold Large 300 - 4.43 6.21 6.38 7.25 7.51 9.69 4.76 20.98 8.90 19.31 6.97 Comm- Small 1,000 - 5.02 12.02 17.99 10.46 11.77 11.67 7.23 20.98 7.55 17.31 8.02 ercial Medium 58,000 180 7.88 12.34 12.73 16.57 11.79 10.67 7.75 20.98 6.76 17.82 6.94 Large 600,000 1,500 5.73 11.96 9.52 15.34 8.67 10.24 7.47 13.56 5.50 16.99 6.56 Industr Small 5,000 - 5.93 9.57 6.87 6.30 10.56 8.65 7.62 20.98 3.61 9.25 8.44 ial Medium 65,000 180 3.66 9.01 7.80 9.08 8.09 8.29 7.15 13.56 4.97 9.84 6.73 Large 270,000 600 4.52 8.67 7.49 8.91 5.82 7.98 6.42 13.54 4.67 9.26 6.14 Very 1,050,000 2,250 4.52 8.62 7.19 8.88 5.40 6.42 6.05 13.54 4.86 9.20 5.86 79 These are average prices to each class customer. Within a class, there are subdivisions with households on an increasing block tariff and other customers on two part tariffs. Inclusive of fuel surcharges. 80 Electricity use and maximum demand have been defined for typical customers. Thus, the average prices calculated reflect the price if each typical customer is located in different countries. Sales taxes such as VAT are not included. Fuel surcharges, if any, are included. These are based on published tariffs. Special concessions given to identified customers or within special economic zones are not included. Optional tariffs (such as time-of-use) are not included. Unity power factor is assumed, where relevant. Prices updated as of 6th January 2009. Sri Lanka: Environmental Issues in the Power Sector 108 ECA, RMA and ERM Review of the past two decades Average unit price of Electricity with unity power factor in each country in USCts/kWh Max. [as of Jan 2009] Elect. Use De- mand Class Maharashtra, Kerala, India Thamilnadu, South Korea Bangladesh Singapore Sri Lanka Malaysia Thailand Pakistan (kWh/ (kW) Nepal month) India India Large Note: the comparison is based on what if each customer is located in each country/state. Fuel surcharges, if any, are included. Sales taxes such as VAT is excluded. Optional time-of-use tariffs and seasonal tariffs are excluded. Unity power factor assumed for countries that charge for maximum demand on the basis of measured apparent power or a power factor penalty. A1.7 Attempts to develop coal-fired power generation The first coal-fired power plant was intended to operate from as early as 1992. However, the Government’s first attempt to build a 300 MW coal-fired power plant in Trincomalee in the East was abandoned in the mid 1990s amidst growing civil unrest in the area and the inability to secure financing for the project. The Asian Development Bank that financed the feasibility study did not proceed with the project to financing and implementation. Trincomalee coal power plant also signifies Sri Lanka’s first attempt to solicit private investments into power generation, although it ended in controversy and failure. With the solicitation beginning in 1993, the initiative was cancelled in 1995, and resulted in prolonged arbitration proceedings between the prospective investor and GOSL81. After the failed attempts to develop Trincomalee, CEB turned its attention to a site in the south at Mawella, where a natural bay was available for development into a small harbour to deliver coal to a power plant to be located in the adjacent land. There were concerns on land availability and the dense population in the coastal zone, and the CEB launched a pre-feasibility study for the site. However, this site too was abandoned after a presidential directive to stop work, presumably as a result of public protests. In 1993, the government also decided to consider siting a power plant on the west coast, in the Kalpitiya peninsula, and a study commenced in 1994, first to locate a suitable site and then to follow-up with a feasibility study. The study focused on the site Norochcholai in Puttalam district, and was completed in 1997 inclusive of the environmental approval issued after the due process. However, public protests and political concerns caused the pre-project activities (such as detailed designs, relocation, financing) to be delayed, cancelled and restarted many times between 1996 and 2005. The final firm decision to build the power plant was made in 2005, and contracts were signed in mid-2006. The project is now under construction (over 50% completed by September 2009) and is targeted for commissioning by the end of 2010. Attempts to build coal-fired power plants in the South, through solicitations issued for an IPP investment, have not been followed-up or have been significantly delayed 81 See http://icsid.worldbank.org/ICSID/FrontServlet?requestType=CasesRH&actionVal=showDoc&docId=D C607_En&caseId=C189 Sri Lanka: Environmental Issues in the Power Sector 109 ECA, RMA and ERM Review of the past two decades owing to a mix of reasons including public protests, lack of finance, poor investor interest, weak approach to procurement and political considerations. A1.8 Power sector reforms Possible models for restructuring of the electricity sector have been under discussion since the late 1990s. Restructuring essentially meant the re-structuring of the vertically integrated CEB. After much debate within and outside Parliament, the Electricity Reform Act of 2002 was introduced. This new Act was to repeal the 1969 Ceylon Electricity Board Act and specified vertical unbundling of the CEB with a single buyer model located in the transmission business and further unbundling of distribution into five different companies. Regulation of the sector and these independent business units were to be handed over to an independent regulatory body. For this, the Public Utilities Commission of Sri Lanka Act was also enacted in the same year (2002) with provisions for the establishment of the Public Utilities Commission (PUCSL) to regulate certain utility industries including electricity. PUCSL came into operation in 2003 with the appointment of the first group of commissioners and the Director General. However, for the commission to exercise its assigned powers over the electricity sector, the Electricity Reform Act had to be fully operational through a Ministerial Order which did not take place because of political opposition and opposition from a section of the CEB staff. Hence, PUCSL has not been fully functional for the past six years and the Electricity Reform Act was dormant. Although several further attempts were made to revise the Act to satisfy various groups, none of the revisions went to Parliament for approval and implementation. With the virtual abandonment of the Electricity Reform Act, the present government took a policy decision to introduce regulatory reforms of the electricity sector without making major structural changes to the CEB. A bill was presented to Parliament in February 2008, followed by many rounds of revisions. The Parliament finally approved the electricity bill and it has now been published as the Electricity Act No. 20 of 2009. With this, the electricity sector of Sri Lanka officially comes under the regulatory purview of the Public Utilities Commission of Sri Lanka. Planning of the generating system has been specifically identified in the new Electricity Act and this function is assigned to the transmission licensee. The transmission licensee is responsible for forecasting the future national demand, planning and development of its own transmission system and procuring new generation plants to meet the forecast demand. The long-term plan has to be submitted for review by the PUCSL. The Act imposes a limitation on private investments in sector operations by requiring a shareholding by the government or a government entity in future generation projects, restricting transmission license to be issued only to CEB, and does not allow a majority shareholding by the private sector in a distribution company. Presently, CEB’s functional business units have been issued with licenses to conduct generation (1 business unit), transmission (1 business unit) and distribution (4 business units). All existing IPPs (9) and SPPs (over 80) have applied for licenses under the new Act based on transition provisions stated in the Act. Sri Lanka: Environmental Issues in the Power Sector 110 ECA, RMA and ERM Detailed assumptions and approaches used A2 Detailed assumptions and approaches used Below we describe the approach used in the analysis to: interest during construction net or gross capacity lower heating value and higher heating value of fuels capital costs of independent power producers A2.1 The treatment of interest during construction (IDC) A first problem in deriving economic capital costs for use in generation expansion planning is the treatment of interest during construction (IDC), which, traditionally, is viewed by the International Financing Institutions (IFIs) as a transfer payment, and is therefore excluded from the economic analysis.82 In classic economic analysis, the overnight cost is apportioned over the construction period, and disbursements, exclusive of IDC, taxes and duties, and financial fees, are booked in the corresponding year. WASP sees just a single capital cost, assumed at the time point of commissioning. This is calculated as the future value of the stream of construction year disbursements at the discount rate, a figure that is (obviously) higher than the overnight cost. For example, in the case of CCGT with a three year construction period, this yields a value 13.54% higher than the overnight cost. It is unfortunate that this adjustment has become known as an “IDC� adjustment: in fact, this calculation is completely unrelated to actual interest during construction (if for no other reason than it is applied to the entire cost, not just the debt portion that in fact attracts IDC). A2.2 Capacity Nameplate capacities can be misleading, particularly for combustion turbines. A 2 x 150 MW GE Frame 9 combustion turbines may be stated as having 300 MW nameplate rating, but the actual output at time of peak demand will be less for two reasons. Firstly, nameplate output is quoted at ISO ambient temperatures (15 degrees C) but the higher the ambient temperature at the time of system peak, the lower the MW output that can be achieved. Higher output may be possible during the night when temperatures are lower, but this is not so valuable for a power system. A gas turbine 82 See e.g. World Bank, Handbook on Economic Analysis of Investment Operations (May 3, 1996), which states with respect to interest during construction Sometimes lending institutions capitalise the interest during construction . . . whether the interest is capitalised or not, its treatment for purposes of economic analysis is the same: interest during construction is still a transfer and is omitted from the economic accounts. Sri Lanka: Environmental Issues in the Power Sector 111 ECA, RMA and ERM Detailed assumptions and approaches used plant’s efficiency is also affected by ambient temperature. Secondly, that nameplate power rating will be dependant upon auxiliaries needed by the plant to manage fuel, and is generally valid only for natural gas (at some stated ambient temperature). Thus, in the case of the West Coast power plant, the combined impact of ambient temperature, fuel oil de-rating, and auxiliary consumption means that the maximum power output is only 280 MW. For this (and other reasons, discussed elsewhere), the preferred numeraire is the net output basis. Capital costs, and heat rates and efficiency, should be quoted on a net basis, since this corresponds to the output of a plant to the system. We recommend that CEB change to such a net system basis for its future generation planning studies: the net basis is adopted here. A2.3 LHV and HHV Whether calorific values and heat rates are specified as lower heating value (LHV) or higher heating value (HHV) is often left unsaid, and care must be exercised to ensure consistency. In Europe, calorific values are generally quoted on a LHV basis, whereas in the US, HHV is generally in use. Ceylon Petroleum Corporation (CPC) uses HHV for petroleum products, which convention is also used by CEB. Special care must be taken with coal, because both gross and net calorific values are in use. Platts International Coal Report quotes coal on a GAR (gross as received) basis – but with exceptions: Europe/ARA, Richards Bay 6,000 kcal/kg, and Japan and Korea West CIF, are quoted on a NAR (net as received) basis. For consistency, the gross basis (HHV) should be used by CEB and in this study as well. A2.4 IPP capital costs Presentations of capital costs by IPPs are notoriously unreliable (a worldwide phenomenon, not limited to Sri Lanka). At best they correspond to the present value of the capacity payments as negotiated in PPAs; at worst they are arbitrary figures presented purely for reasons of negotiation strategy or public relations. Absent a competitive solicitation for a two-part tariff that includes a competitively bid capacity charge (with the discount rate clearly stated), IPP capital cost estimates require great caution. Even if competitively bid, they will include financial costs, IDC, and unknown returns to developer’s equity. In the case of foreign IPPs, where capacity charges are remitted overseas, the economic cost to the country is indeed the present value of capacity charges at the relevant discount rate. This is also the approach to be taken for the Norochchollai coal project, which, though owned by CEB, is 100% financed by China: the economic cost is therefore the PV of the foreign currency payments made by the GoSL. Depending on the onlending terms to CEB, these may not correspond to CEB’s capital costs: in the Sri Lanka: Environmental Issues in the Power Sector 112 ECA, RMA and ERM Detailed assumptions and approaches used reconciliation of economic and financial flows, any difference would be booked as a (financial) gain or loss to the Ministry of Finance.83 83In the specific case of the Norochallai project, it is understood that the onlending terms are still under discussion: CEB has proposed that the onlending be in $ at identical terms (in other words that CEB assumes the FOREX risk). Sri Lanka: Environmental Issues in the Power Sector 113 ECA, RMA and ERM Carbon accounting A3 Carbon accounting As shown in Table 48, per capita GHG emissions in Sri Lanka are not only well below those of other countries with similar per capita income levels - for example, Sri Lanka’s per capita GHG emissions are half those of India - but are 15% of the global average. This relative positioning will remain true even with significant increases in GHG emissions attributable to coal-based power generation. Table 48 GHG emissions per capita Country Name 1970 1980 1990 2000 2005 United States 20.57 20.26 19.22 20.01 19.52 Singapore 8.77 12.47 13.76 12.89 13.19 Japan 7.08 7.88 8.75 9.49 9.63 Euro area 8.26 9.26 8.39 7.95 8.07 World 4.06 4.41 4.29 4.07 4.53 China 0.94 1.51 2.11 2.64 4.26 Indonesia 0.28 0.63 0.84 1.36 1.90 India 0.35 0.51 0.80 1.14 1.28 Philippines 0.67 0.76 0.72 1.02 0.89 Pakistan 0.39 0.38 0.63 0.77 0.86 Vietnam 0.66 0.31 0.32 0.69 1.23 Sri Lanka 0.29 0.22 0.22 0.54 0.56 Lao PDR 0.22 0.06 0.06 0.20 0.25 Bangladesh 0.05 0.09 0.14 0.20 0.26 Myanmar 0.16 0.14 0.11 0.19 0.24 Cambodia 0.17 0.04 0.05 0.04 0.04 Source: World Bank World Development Indicators Database Nevertheless, there are two issues in carbon accounting of importance to the present study. The first relates to GHG emissions from hydro reservoirs (relevant to the hydro and renewable energy scenarios). The second is whether to consider just the GHG emissions from combustion (which are straightforward), or whether to include life- cycle emissions. Each of these issues is considered below, beginning with GHG emissions from hydro reservoirs. Sri Lanka: Environmental Issues in the Power Sector 114 ECA, RMA and ERM Carbon accounting A3.1 GHG emissions from reservoirs GHG emissions from hydro dams is a controversial topic. This tension is captured in three points from the 2000 World Commission on Dams84, points still valid. Specifically, Hydropower cannot, a priori, be automatically assumed to emit less greenhouse gas than the thermal alternatives. Net emissions should be established on a case by case basis. The flooded biomass alone does not explain the observed gas emissions. Carbon is flowing into the reservoir from the entire basin upstream, and other development and resource management activities in the basin can increase or decrease future carbon inputs to the reservoir. As natural habitats also emit greenhouse gases it is the net change due to impoundment that should be used for assessment, and not the gross emissions from the reservoir. In recognition of these issues, it has become increasingly common to proxy the GHG efficiency of a hydro project through the power density, or watts/m2 of reservoir area, The UNFCCC has issued a draft guideline for the clean development mechanism (CDM) eligibility of hydro projects using this measure:85 Projects with power densities (installed power generation capacity divided by the flooded surface area) less than or equal to 4 W/m2 are excluded; Projects with power densities greater than 4 W/m2 but less than or equal to 10 W/m2 can be eligible, but with an emission penalty of 90 g CO2eq/kWh; Projects with power densities greater than 10 W/m2 are eligible without penalty. The UNFCCC notes that in a database of 245 hydro plants in operation in the world today with at least 30 MW of installed capacity, the average power density is 2.95W/m2; i.e., the “average� hydro project would not be eligible for CDM, thereby negating the assumptions of their low carbon moniker. The power density of the four medium-sized Sri Lankan hydro projects is shown in Table 49, together with values for some existing projects, and values for small hydro schemes that would be representative of the renewable energy scenario in our study. 84 World Commission in Dams, Final report on Dams and Development A New Framework for Decision-making to the Framework Convention on Climate Change, November 2000. 85 UNFCCC CDM Methodology Panel, Nineteenth Meeting Report, Annex 10, Draft Thresholds and Criteria for the Eligibility of Hydroelectric Reservoirs as CDM Projects. Sri Lanka: Environmental Issues in the Power Sector 115 ECA, RMA and ERM Carbon accounting Table 49 Power densities, Sri Lanka hydro projects Project Installed Reservoir Power Capacity area density MW km2 W/m2 Candidates Umna Oya 150 0.84 179 Broadlands 35 0.038 Moragolla 28.4 0.8 41 Gin Ganga 48.9 1.7 29 These Sri Lankan values compare favourably with the range of power densities for Brazilian projects for which detailed methane and CO2 flux survey data is available (and which are the basis for the thresholds proposed by UNFCCC) (Table 50). Table 50 Power densities for Brazilian hydro projects Project Province Installed Reservoir Power capacity area density MW km2 W/m2 Uma Oya Sri Lanka 150 0.84 179 Xingo Caatinge 3000 60 50 Moragolla Sri Lanka 28.4 0.8 41 Gin Ganga Sri Lanka 48.9 1.7 29 Segredo Mata Atlantica 1260 82 15 Itaipu Mata Atlantica 12000 1,549 8.13 Miranda Cerrado 390 50.6 7.72 Tucuri Amazonica 4240 2,430 1.74 Serra da Mesa Cerrado 1275 1,784 0.71 Barra Bonita Mata Atlantica 141 312 0.45 Samuel Amazonica 216 559 0.39 Tres Marias Cerrado 396 1,040 0.38 Source: Marco Aurélio dos Santos et al., Variability of Greenhouse Gas Fluxes from Hydropower Reservoirs in Brazil, UNESCO Workshop on Freshwater reservoirs and GHG emissions, Paris, November 2006. As all of the Sri Lanka hydro candidates have significantly higher power densities (above 29 W/m2) than the lower bound for CDM projects eligible without penalty (i.e., greater than 10 W/m2, whereas projects with power densities between 4 and 10 W/m2 have a penalty of 90kgCO2 /MWh) we may ignore methane and CO2 fluxes from these projects. Sri Lanka: Environmental Issues in the Power Sector 116 ECA, RMA and ERM Carbon accounting A3.2 Life cycle emissions The increasing attention to life cycle emissions is largely the consequence of criticism about claims regarding the GHG benefits of nuclear and hydro generation, and the recognition that all technologies, including renewable generation such as wind, have an impact on GHG emissions. This impact is by virtue of the energy required for the manufacture of equipment, as well as in fuel extraction, transport and decommissioning. There is little doubt that the bulk of GHG emissions associated with thermal generation technologies derive from actual fuel combustion. The necessary calculations are relatively straightforward and uncontroversial, and subject to relatively modest uncertainties. However, whether one should account for these indirect impacts as well as the direct impacts of combustion depend upon the answers to two further questions: How large are these impacts compared to combustion? Can reliable calculations of indirect impacts be made, and, if so, under what circumstances is the burden of calculation reasonable? In response to the first question, and in leaving aside the more extreme claims, the consensus of the technical literature appears to be that, in general, the life cycle emissions associated with mining, transport, materials inputs, construction and decommissioning represent 5-10% of lifecycle emissions for most fossil fuel technologies.86 For non-fossil fuel plant, a review of the recent literature on life-cycle emissions estimates from some 50 studies (and the results of which are summarised in Figure 55) show that hydro, nuclear and wind all have life-cycle emissions in the range of 10-40gCO2/kWh. This is in comparison to 800-1300gCO2/kWh for coal. 86Life cycle emission calculations may depend upon highly variable site specific circumstances. For example, in a study of life cycle GHG emissions for wind projects in Brazil and Germany (M. Lenzen & U Wachsman, Wind Energy Converters in Brazil and Germany: An example of Geographic Variability, Applied Energy, 2004 (77) 119-130) it was found that the emissions related to steel manufacture depend critically on the proportion of scrap used (high in Germany, low in Brazil), and on the generation mix of electricity used in manufacturing industry (low emissions in hydropower dominated Brazil, high emissions in Brown coal dominated Germany): in some cases – as in this comparative study of Brazil and Germany, these may cancel out, but in others not, leading to large differences in values. Sri Lanka: Environmental Issues in the Power Sector 117 ECA, RMA and ERM Carbon accounting Figure 55 Summary of Life-Cycle GHG Emissions Source: D. Weisser, A Guide to Life-cycle GHG emissions from electric supply technologies, Energy (32) 2007, pp. 1543-1559. With regard to LNG, one of the generation options considered in this study, consider a study on Japan87 which reveals quite high values for non-combustion impacts of LNG. As shown in Figure 56, the indirect emission factors for an LNG CCGT are 111g CO2/kWh and, for a steam cycle LNG fuelled project, 130g/kWh. These values are the largest for any technology, and significantly higher than for coal projects (88g CO2/kWh). Figure 56 Life-cycle GHG emission factors Source: H. Hondo, Life cycle GHG emission analysis of power generation systems: The Japanese Case, Energy,30 (2005) 2042-2056. 87Source: H. Hondo, Life cycle GHG emission analysis of power generation systems: The Japanese case, Energy,30 (2005) 2042-2056. Sri Lanka: Environmental Issues in the Power Sector 118 ECA, RMA and ERM Carbon accounting Furthermore, not only is liquefaction an energy intensive process, but there is a high content of CO2 in the extracted gas, which is released during processing. This release can be up to 20-30% as is the case in Indonesia.88 For gas-fuelled plants there is the further issue of leakage, which, given a global warming potential of 23 times that of CO2, has a disproportionate impact on aggregate GHG emissions. In the Japan study, methane leakage in LNG production was estimated at 9 g/kWh, with a further 19.4 g/kWh in LNG transportation. The most comprehensive study of life-cycle emissions in the LNG supply chain in the literature is that by Heede for the Cabrillo deepwater port that is part of a proposal for an LNG project in California89. This study (see Table 51) shows that consideration of the LNG supply chain adds some 38% to the GHG emissions resulting from combustion (both CO2 and methane). We assume the adder, on top of combustion emissions, is 40%. Table 51 GHG emissions in the LNG supply chain Supply-chain segment Methane CO2 Total Share (CO2 (CO2 equivalent) equivalent) Gas production (Scarborough) 297 494 791 3.5% Gas pipeline to Pilbara LNG 135 264 399 1.7% Liquefaction plant at Onslow 175 2,512 2,687 11.8% LNG carrier fleet, Australia→California 47 2,048 2,095 9.2% Cabrillo deepwater port operations 85 261 346 1.5% Cabrillo start-up (annualised, 25 years) ~ 0.4 0.4 0.0% Ultimate gas distribution & combustion 650 15,852 16,502 72.3% Total supply chain LNG emissions 1,389 21,434 22,823 100% Share 6.1% 93.9% 100% Source: A Heede, LNG Supply Chain GHG emissions for the Cabrillo Deepwater Port: Natural gas from Australia to California, Report by Climate Mitigation Services, 2006. In the case of coal plants, much depends on the technology and efficiency, with ultra- supercritical plants having significantly lower emissions than present sub-critical projects (Table 52). This, however, is mainly a consequence of better efficiency, rather than different life cycle impacts. 88 Similarly in Vietnam, the gas field supplying the O Mon power complex (Block Ba nd 52) is reported to contain 23% inert gas. 89 A Heede, LNG Supply Chain GHG emissions for the Cabrillo Deepwater Port: Natural gas from Australia to California. Report by Climate Mitigation Services, 2006. Sri Lanka: Environmental Issues in the Power Sector 119 ECA, RMA and ERM Carbon accounting Table 52 GHG emissions for coal technologies Steam Steam Thermal Life cycle emissions temperature pressure efficiency g CO2 /kWh (OC) (Mpa) Subcritical 540 16.6 37.6% 941 Supercritical 560 25 43% 788 Ultra-supercritical 630 30 45.3% 716 Source: University of Sydney, Life Cycle Energy Balance and GHG Emissions of Nuclear Energy in Australia, Report to the Australian Government, 3 November 2006, Table 6.13 As one last example, consider Table 53, which compares the life cycle emissions for coal and hydro in an Australian study. The results for hydro are similar to those in the Japanese study, with life cycle emissions for Australian hydro being 14.9 g/kWh as compared to 11g/kWh in Japan. (Note that the hydro estimates do not include any reservoir impacts but do include dam construction.) However, the results for coal differ in that the Japanese results are significantly higher because they include the transportation over long distances from distant mines (in Australia) – transportation distances that apply to Sri Lanka as well. Table 53 GHG emissions for coal and hydro Super-critical coal Hydro (run-of-river) mine-mouth gCO2/kWh % of gCO2/kWh % of total total Mining 33.0 3.2% Transport 0.4 0.0% 0.2 1.6% Construction 6.9 0.7% 3.3 22.2% Materials 11.4 76.2% Combustion 995.5 96.1% Decommissionin 0.3 0.0% g Total 1,036.1 100.0% 14.9 100% Source: University of Sydney, Life Cycle Energy Balance and GHG Emissions of Nuclear Energy in Australia, Report to the Australian Government, 3 November 2006, Table 6.13 Sri Lanka: Environmental Issues in the Power Sector 120 ECA, RMA and ERM Load Forecast A4 Load Forecast A4.1 Introduction The electricity demand projections prepared by the Ceylon Electricity Board (CEB) are normally based on econometric analysis, but the CEB forecasting model recently failed to predict the degree to which electricity demand growth fell in response to the economic downturn in the second half of 2008. While GNP continued to increase at 5% to 6% per year in 2008, electricity demand growth dropped to only 1.4% (at the time of the CEB forecast the estimate was that demand growth would be between 3% and 6% but the outturn was lower still). For the purposes of the latest generation investment plan, CEB therefore temporarily adopted a time trend approach and made an ad hoc adjustment to the forecast for 2009 and assumed a growth rate of 4.6%. This Annex reviews CEB’s trend forecast and its normal econometric forecasting model, and describes the load forecast prepared by the Consultant to be used as part of the EIPS analysis. A4.2 CEB forecasting model and forecasts A4.2.1 Time trend model The most recent forecast used by CEB is based on a time-trend model where the time trend is derived from sales data from 1978 to the present. The forecast is prepared at an aggregate level without dividing forecast demand into sectors. The average trend growth rate over this period was estimated by CEB at 6.7% per annum. CEB’s forecast is prepared by applying the trend growth rate of 6.7% to sales from 2010 onwards. Sales in 2009 were assumed by CEB to grow at 4.6% compared with 2008. To estimate gross generation and MW demand the sales forecasts were adjusted based on assumed losses and load factors, as shown in Table 54 below. Table 54 CEB’s 2008 base load forecast Year Demand Growth Gross Generation Load Peak (GWh) rate losses90 (GWh) factor demand (MW) 2008 8,527 3.0% 15.7% 9,863 57.0% 1,974 2009 8,923 4.6% 15.5% 10,307 57.2% 2,058 2010 9,523 6.7% 15.3% 11,250 57.3% 2,241 2011 10,165 6.7% 15.0% 11,959 57.4% 2,376 2012 10,849 6.7% 14.8% 12,730 57.6% 2,524 2013 11,579 6.7% 14.6% 13,559 57.7% 2,681 90Gross losses include losses at all levels including auxiliary consumption at the power plant, transmission and distribution losses and non-technical (commercial) losses. Sri Lanka: Environmental Issues in the Power Sector 121 ECA, RMA and ERM Load Forecast Year Demand Growth Gross Generation Load Peak (GWh) rate losses90 (GWh) factor demand (MW) 2014 12,359 6.7% 14.7% 14,496 57.9% 2,860 2015 13,191 6.7% 14.4% 15,401 58.0% 3,031 2016 14,079 6.7% 14.2% 16,412 58.1% 3,222 2017 15,026 6.7% 14.0% 17,476 58.3% 3,423 2018 16,038 6.7% 14.0% 18,652 58.4% 3,645 2019 17,118 6.7% 14.0% 19,908 58.6% 3,881 2020 18,270 6.7% 14.0% 21,248 58.7% 4,133 2021 19,500 6.7% 14.0% 22,679 58.8% 4,401 2022 20,812 6.7% 14.0% 24,206 59.0% 4,686 2023 22,214 6.7% 14.0% 25,835 59.1% 4,989 2024 23,709 6.7% 14.0% 27,574 59.2% 5,313 2025 25,305 6.7% 14.0% 29,430 59.4% 5,657 2026 27,009 6.7% 14.0% 31,412 59.5% 6,024 2027 28,827 6.7% 14.0% 33,526 59.7% 6,415 2028 30,767 6.7% 14.0% 35,783 6,847 The forecast for losses includes 1% for auxiliary consumption in power plants and an overall target level of 14% expected to be achieved by 2017 (from 15.7% today). The forecast for the load factor is based on an extrapolation of past load factors (excluding years with load shedding). We note that this improvement in the load factor may be optimistic in the light of the expected growth in residential electricity demand (see Section A4.2.2 below - which typically has a low load factor) compared with industry, and the impact this is likely to have on the overall system load factor. A4.2.2 CEB’s econometric model CEB’s Long Term Generation Expansion Plan: 2009-2022 prepared in December 200891 had adopted CEB’s traditional demand forecasting model based on econometric analysis of electricity sales by sector against independent variables such as GDP, population and electricity price. In some cases dynamic relationships are incorporated into the forecasting equations. The structure of the equations, the included parameters and the coefficients used in the equations change from year to year depending on the latest data and the results of the regression analysis. CEB’s approach for each forecast is to update the database and with the new data to identify the relationship between demand and independent variables that gives the best statistical fit. Because of changes in the definition of tariff categories over time, only two main sectors and one ‘other’ sector are used in this analysis, including: 91The Plan also described a least-cost plan based on a time-trend forecast. The results of this analysis were presented in an Annex to the Plan. Sri Lanka: Environmental Issues in the Power Sector 122 ECA, RMA and ERM Load Forecast domestic, industrial and general purpose (including hotels), and other (religious buildings, street lighting). The equations estimated in the December 2008 Long Term Generation Expansion Plan: 2009-2022 are shown in Table 55 below. Table 55 CEB demand forecasting model – econometric analysis Dependent Estimated equation variable Domestic Ddom (t) -653.412 + 0.031 GDPPC(t) + 0.712 Ddom (t-1) where: Ddom (t) = Domestic sales (GWh) in year t GDPPC(t) = GDP per capita in year t Ddom (t-1) = Domestic sales in year t-1 Industrial and general purpose Di (t) -751.815 + 0.005 GDP(t) where: Di (t) = Industrial and general purpose sales (GWh) in year t GDP(t) = GDP in year t Other (religious buildings, street lighting) Dos(t) -117.500 + 0.061t where: Dos(t) = Other92 sales (GWh) in year t t = Year We note that the latest regression analyses, as with previous analyses, did not identify electricity price as a significant determinant of electricity demand. In the case of domestic demand a dynamic relationship was indicated by the data. This implies a lagged adjustment of demand to changes in per capita GDP. The effect of a change in GDP in the short-term is to increase GWh sales by 0.031 times the change in GDP per capita. The long-run effect of a change in per capita GDP is to increase GWh sales by 0.108 times the change in GDP per capita93. 92 Religious buildings and street lighting. 93 Calculated as 0.031 / (1 – 0.712). Sri Lanka: Environmental Issues in the Power Sector 123 ECA, RMA and ERM Load Forecast We note that CEB assumes a linear relationship between the independent and dependent variables which implies that, for example, a 10% increase in GDP will have a gradually smaller percentage impact on GWh sales over time as GDP grows. The more widely used international practice in econometric analysis of demand is to assume a log-linear relationship such that a 10% change in GDP would have the same percentage impact on GWh sales as GDP and GWh sales grow over time. We understand that the external drivers in the econometric equations above (GDP) were provided by the Central Bank of Sri Lanka (CBSL). The resulting forecast is shown in Table 56. As with the time trend forecast, the forecasts for losses and system load factors are estimated by CEB. Table 56 CEB’s 2007 base load forecast Year Demand Growth Gross Generation Load Peak (GWh) rate losses94 (GWh) factor demand (MW) 2008 8,644 6.5% 16.2% 10,314 57.0% 2,064 2009 9,533 10.3% 15.7% 11,313 57.2% 2,259 2010 10,393 9.0% 15.4% 12,283 57.3% 2,447 2011 11,373 9.4% 14.9% 13,360 57.4% 2,655 2012 12,429 9.3% 14.5% 14,529 57.6% 2,880 2013 13,560 9.1% 14.5% 15,861 57.7% 3,137 2014 14,767 8.9% 13.9% 17,156 57.9% 3,385 2015 16,051 8.7% 14.0% 18,668 58.0% 3,674 2016 17,416 8.5% 14.0% 20,255 58.1% 3,977 2017 18,868 8.3% 14.0% 21,944 58.3% 4,298 2018 20,423 8.2% 14.0% 23,753 58.4% 4,642 2019 22,088 8.2% 14.0% 25,689 58.6% 5,008 2020 23,871 8.1% 14.0% 27,763 58.7% 5,400 2021 25,784 8.0% 14.0% 29,988 58.8% 5,819 2022 27,840 8.0% 14.0% 32,379 59.0% 6,268 2023 30,047 7.9% 14.0% 34,946 59.1% 6,749 2024 32,415 7.9% 14.0% 37,700 59.2% 7,264 2025 34,955 7.8% 14.0% 40,654 59.4% 7,815 2026 37,683 7.8% 14.0% 43,826 59.5% 8,405 2027 40,615 7.8% 14.0% 47,236 59.7% 9,038 Note: The growth rates shown in the above Table are calculated and differ slightly from those in the CEB Generation Plan (Table 3.2). 94Gross losses include losses at all levels including auxiliary consumption at the power plant, transmission and distribution losses and non-technical (commercial) losses. Sri Lanka: Environmental Issues in the Power Sector 124 ECA, RMA and ERM Load Forecast A4.3 Consultant’s forecast A4.3.1 Data sources CEB maintains good records of electricity sales, GDP, population and price data from 1978 onwards. These data were supplemented where necessary with information from the Central Bank of Sri Lanka on inflation and population growth. Historic GDP data were converted to 2002 factor cost and electricity prices (average revenue by customer group) were converted to prices of 2008. A4.3.2 Forecasting model We noted above that CEB does not adopt the more widely used practice of assuming a log-linear relationship. For the purposes of the current exercise we have adopted a forecast of the general form: E = K GDPα pβ (1) where: E is demand for electricity K is a constant α is an income elasticity β is the price elasticity P is the price This equation can be re-written as: log (E) = log (K) + α log (G) + β log (p) (2) Because this is a linear equation in the logarithmic quantities α and β can be estimated by simple linear regression. Our approach has been to specify a general form of the above equation including dynamic forms (lagged dependent variable) and to test the specifications using standard econometric tests with the objective of identifying a model that makes economic sense and that is supported by the data. We considered electricity intensity (GWh/GDP) as the dependent variable but the data did not support this specification of the equation for either the domestic sector or the industrial and general sector. The unconstrained form of the equation, with GWh as the dependent variable, was therefore selected. Domestic sales The final version of the equation selected for the forecast for domestic sales is shown in Table 57 below. Sri Lanka: Environmental Issues in the Power Sector 125 ECA, RMA and ERM Load Forecast Table 57 Estimated equation for domestic sales Dependent Estimated equation variable Ln (Ddom(t)) -7.211 + 0.51 Ln(Ddom(t-1)) + 0.77 Ln (GDP(t)) - 0.036 Ln (P(t)) t-statistics -3.302 3.613 3.377 -0.627 Adjusted R2 99.5% where: Ddom(t) = Domestic sales (GWh) in year t Ddom(t-1) = Domestic sales in year t-1 GDP(t) = GDP in year t P(t) = Average real (2008) price in year t The specification of the equation is similar to that adopted by CEB and described in Section A4.2 except that the variables are all expressed as natural logs, GDP is total GDP rather than GDP per capita and we have included a price term. The variables in the equation are found to be statistically significant95 with the exception of real price. Even though price is not statistically significant we have included it in the forecasting equation96. The above equation indicates that the response to changes in GDP and price do not all occur within the year. The long-term elasticities indicate how a percentage change in price or GDP results in a percentage change in GWh sales. The long-term elasticities are 1.57 for GDP and -0.073 for price97. These show that for every one percent increase in GDP, GWh sales increase by 1.57% and for every one percent increase in price, GWh sales will fall by 0.073%. This suggests a relatively weak impact of price on sales. Industrial and general The final version of the equation selected for the forecast for industrial and general sales is shown in Table 58 below. 95The t-statistic in absolute terms exceeds 2. There is inevitably a certain degree of uncertainty around the estimated values of the coefficients; when the t-statistic exceeds a value of approximately 2 then this means that it is very unlikely that the true value of the coefficient is actually zero (ie, it is unlikely that there is no relationship between the variable and sales). 96 In econometric terminology, the t-statistic indicates that we cannot reject the hypothesis that the coefficient is actually zero. But the results do not tell us that the coefficient is zero and, based on economic theory, we can legitimately include a price variable in the equation. 97 This is calculated by dividing the short-term coefficient or elasticity by (1 – coefficient on the lagged dependent variable). Sri Lanka: Environmental Issues in the Power Sector 126 ECA, RMA and ERM Load Forecast Table 58 Estimated equation for domestic sales Dependent Estimated equation variable Ln (E(t)) -10.591 + 1.3098 Ln (GDP(t)) - 0.021 Ln (P(t)) t-statistics -30.150 66.348 -0.529 Adjusted R2 99.6% where: E(t) = Industrial and general sales (GWh) in year t GDP(t) = GDP in year t P(t) = Average real (2008) price levels in year t The specification of this equation is also similar to that adopted by CEB and described in Section A4.2 except that the variables are all expressed as natural logs and we have included a price term. The variables in the equation are again found to be statistically significant98 with the exception of real price. Even though price is not statistically significant we have included it in the forecasting equation99. The dynamic form of the equation was not found to be supported by the data and implied that changes in GDP and price impact on GWh sales within the same year. The elasticities shown in the Table above are therefore both short-term and long term. They indicate that for every one percent increase in GDP, GWh sales will increase by 1.3098% and for every one percent increase in price, GWh sales will fall by 0.021%. Other We have adopted an approach similar to that of CEB for the ‘other’ sector (street lighting and religious buildings); here the relationship is described by a trend relating to time and estimated over the period 1999 to 2008. Our estimated equation shows that ‘other’ sales grow by 5.8% per year. This is slightly lower than the value of 6.1% estimated by CEB. A4.3.3 Forecast To prepare a base forecast we have adopted similar assumptions on load factor and losses to those assumed by CEB in the latest (trend) forecast and described in Section A4.2.1. We obtained projections of GDP to the year 2012 from the Central Bank of Sri Lanka with growth rates of 2.5%, 5.0%, 6.0% and 6.5% in 2009 to 2012 respectively. Beyond 2012 we assume that GDP growth will be 6% per year for five years (2013-17), 98 The t-statistic in absolute terms exceeds 2. There is inevitably a certain degree of uncertainty around the estimated values of the coefficients; when the t-statistic exceeds a value of approximately 2 then this means that it is very unlikely that the true value of the coefficient is actually zero (ie, it is unlikely that there is no relationship between the variable and sales). 99 See footnote 96. Sri Lanka: Environmental Issues in the Power Sector 127 ECA, RMA and ERM Load Forecast 5% per year for the next five years (2018-22), and 4.5% per year thereafter. The resulting forecast is shown in Table 59 (together with actual data for 2007 and 2008). Table 59 Consultant’s sales forecast Domestic I&G Other Total (GWh) (% p.a.) (GWh) (% p.a.) (GWh) (% p.a.) (GWh) (% p.a.) 2007a 3,219 4,824 186 8,229 2008a 3,230 0.3% 4,936 2.3% 182 -2.2% 8,348 1.4% 2009 3,230 0.0% 4,936 0.0% 182 0.0% 8,348 0.0% 2010 3,735 15.6% 5,259 6.5% 193 5.8% 9,187 10.1% 2011 4,208 12.7% 5,673 7.9% 204 5.8% 10,085 9.8% 2012 4,695 11.6% 6,155 8.5% 216 5.8% 11,066 9.7% 2013 5,194 10.6% 6,639 7.9% 228 5.8% 12,061 9.0% 2014 5,720 10.1% 7,161 7.9% 241 5.8% 13,122 8.8% 2015 6,286 9.9% 7,724 7.9% 255 5.8% 14,265 8.7% 2016 6,899 9.8% 8,331 7.9% 270 5.8% 15,500 8.7% 2017 7,569 9.7% 8,985 7.9% 286 5.8% 16,840 8.6% 2018 8,239 8.9% 9,574 6.5% 302 5.8% 18,116 7.6% 2019 8,935 8.4% 10,201 6.5% 320 5.8% 19,456 7.4% 2020 9,670 8.2% 10,869 6.5% 338 5.8% 20,877 7.3% 2021 10,455 8.1% 11,581 6.5% 358 5.8% 22,394 7.3% 2022 11,298 8.1% 12,339 6.5% 379 5.8% 24,016 7.2% 2023 12,161 7.6% 13,066 5.9% 401 5.8% 25,628 6.7% 2024 13,063 7.4% 13,836 5.9% 424 5.8% 27,323 6.6% 2025 14,018 7.3% 14,652 5.9% 449 5.8% 29,118 6.6% 2026 15,034 7.3% 15,515 5.9% 475 5.8% 31,024 6.5% 2027 16,120 7.2% 16,430 5.9% 502 5.8% 33,052 6.5% 2028 17,282 7.2% 17,398 5.9% 531 5.8% 35,212 6.5% 2029 18,527 7.2% 18,424 5.9% 562 5.8% 37,512 6.5% 2030 19,860 7.2% 19,509 5.9% 595 5.8% 39,964 6.5% 2031 21,289 7.2% 20,659 5.9% 629 5.8% 42,578 6.5% 2032 22,821 7.2% 21,877 5.9% 666 5.8% 45,363 6.5% 2033 24,462 7.2% 23,166 5.9% 704 5.8% 48,333 6.5% We note that the model predicts a relatively rapid growth rate of domestic sales in 2009 despite the forecast growth rate in GDP of only 2.5%. This is counterintuitive given the economic situation in Sri Lanka and reflects that the model would, as would CEB’s model, have over-forecast demand in 2008. The rapid growth in 2009 is the result of the model forecasting a return to the ‘normal’ relationship. It should be remembered that though forecasting models such as the one above and CEB’s econometric model are expected to be unbiased – so that there is no systematic bias toward over- or under-forecasting sales – the forecasting models are not expected to predict demand accurately each year. There are inevitable random factors at work that mean demand forecasts will generally be above or below the outturn. The equation for domestic sales, for example, has a standard error of 4.1% which implies that for approximately two thirds of the time the forecast should be ± 4.1% of the outturn value and for 95% of the time the forecast should be ± 8.2% of the outturn value. This range of accuracy presumes that the GDP forecast is perfectly accurate which, of course, it is not so that the range of uncertainty will be magnified further. Despite a degree of inaccuracy the model is valuable for the purpose of long-range generation planning and perfectly suited to the EIPS project. The forecast of gross generation and maximum demand forecast are shown in Table 60 below. Sri Lanka: Environmental Issues in the Power Sector 128 ECA, RMA and ERM Load Forecast Table 60 Consultant’s gross generation and maximum demand forecast Year Total sales Losses Net Load factor Peak demand (net, sent out) generation (GWh) (%)100 (GWh) (MW) (% pa) 2007a 8,229 16.2% 9,814 60.8% 1,842 2008a 8,348 15.7% 9,901 58.8% 1,922 4.4% 2009 8,348 14.5% 9,764 57.2% 1,949 1.4% 2010 9,187 14.3% 10,720 57.3% 2,136 9.6% 2011 10,085 14.0% 11,726 57.4% 2,332 9.2% 2012 11,066 13.8% 12,838 57.6% 2,544 9.1% 2013 12,061 13.6% 13,960 57.7% 2,762 8.5% 2014 13,122 13.7% 15,206 57.9% 2,998 8.5% 2015 14,265 13.4% 16,472 58.0% 3,242 8.1% 2016 15,500 13.2% 17,857 58.1% 3,509 8.2% 2017 16,840 13.0% 19,356 58.3% 3,790 8.0% 2018 18,116 13.0% 20,822 58.4% 4,070 7.4% 2019 19,456 13.0% 22,363 58.6% 4,356 7.0% 2020 20,877 13.0% 23,997 58.7% 4,667 7.1% 2021 22,394 13.0% 25,740 58.8% 4,997 7.1% 2022 24,016 13.0% 27,604 59.0% 5,341 6.9% 2023 25,628 13.0% 29,457 59.1% 5,690 6.5% 2024 27,323 13.0% 31,406 59.2% 6,056 6.4% 2025 29,118 13.0% 33,469 59.4% 6,432 6.2% 2026 31,024 13.0% 35,660 59.5% 6,842 6.4% 2027 33,052 13.0% 37,991 59.7% 7,264 6.2% 2028 35,212 13.0% 40,473 59.7% 7,739 6.5% 2029 37,512 13.0% 43,118 59.7% 8,245 6.5% 2030 39,964 13.0% 45,936 59.7% 8,784 6.5% 2031 42,578 13.0% 48,940 59.7% 9,358 6.5% 2032 45,363 13.0% 52,142 59.7% 9,970 6.5% 2033 48,333 13.0% 55,555 59.7% 10,623 6.5% Losses exclude auxiliary consumption in the power plants. Generation and peak demand refer to energy and power “sent out� to the transmission system (ie., not at the generator terminals). A4.4 Comparison between forecasts A comparison between CEB’s and the Consultant’s forecasts is provided in Table 61. It should be noted that at the time CEB prepared its forecast, full data for 2008 was not available. 100 Percentage of generation. Sri Lanka: Environmental Issues in the Power Sector 129 ECA, RMA and ERM Load Forecast Table 61 Sales forecast comparisons Year Sales Maximum demand Consultant CEB Consultant (net, CEB (gross, sent out) generation) (GWh) (% p.a) (GWh) (% p.a) (MW) (% p.a) (MW) (% p.a) 2008a 8,348 1.4% 8,527 3.6% 1,922 4.4% 1,974 7.2% 2009 8,348 0.0% 8,923 4.6% 1,949 1.4% 2,058 4.3% 2010 9,187 10.1% 9,523 6.7% 2,136 9.6% 2,241 8.9% 2011 10,085 9.8% 10,165 6.7% 2,332 9.2% 2,376 6.0% 2012 11,066 9.7% 10,849 6.7% 2,544 9.1% 2,524 6.2% 2013 12,061 9.0% 11,579 6.7% 2,762 8.5% 2,681 6.2% 2014 13,122 8.8% 12,359 6.7% 2,998 8.5% 2,860 6.7% 2015 14,265 8.7% 13,191 6.7% 3,242 8.1% 3,031 6.0% 2016 15,500 8.7% 14,079 6.7% 3,509 8.2% 3,222 6.3% 2017 16,840 8.6% 15,026 6.7% 3,790 8.0% 3,423 6.2% 2018 18,116 7.6% 16,038 6.7% 4,070 7.4% 3,645 6.5% 2019 19,456 7.4% 17,118 6.7% 4,356 7.0% 3,881 6.5% 2020 20,877 7.3% 18,270 6.7% 4,667 7.1% 4,133 6.5% 2021 22,394 7.3% 19,500 6.7% 4,997 7.1% 4,401 6.5% 2022 24,016 7.2% 20,812 6.7% 5,341 6.9% 4,686 6.5% 2023 25,628 6.7% 22,214 6.7% 5,690 6.5% 4,989 6.5% 2024 27,323 6.6% 23,709 6.7% 6,056 6.4% 5,313 6.5% 2025 29,118 6.6% 25,305 6.7% 6,432 6.2% 5,657 6.5% 2026 31,024 6.5% 27,009 6.7% 6,842 6.4% 6,024 6.5% 2027 33,052 6.5% 28,827 6.7% 7,264 6.2% 6,415 6.5% 2028 35,212 6.5% 30,767 6.7% 7,739 6.5% 6,847 6.7% 2029 37,512 6.5% 8,245 6.5% 2030 39,964 6.5% 8,784 6.5% 2031 42,578 6.5% 9,358 6.5% 2032 45,363 6.5% 9,970 6.5% 2033 48,333 6.5% 10,623 6.5% The Consultant’s forecast begins at a slightly lower level than CEB’s. This reflects the more up-to-date information available to the Consultant at the time this forecast was prepared. Generally, however, the Consultant’s forecast is slightly higher than CEB’s. This reflects in large part the use of the log-linear relationship in the econometric model – the linear form adopted by CEB tends to dampen the impact of GDP growth in the medium-term and dampens it even further in the long term. Sri Lanka: Environmental Issues in the Power Sector 130 ECA, RMA and ERM Fuel price forecasts A5 Fuel price forecasts A5.1 Oil and petroleum product prices A5.1.1 Oil price forecasts The IEA energy price forecasts in the 2008 World Energy Outlook are shown in Table 62. These anticipate a 2015 crude oil price of 100$/bbl (at constant 2007 prices)101. The corresponding nominal prices assume an annual inflation rate of 2.3%. Prices (at 2007 price levels) rise to 116$/bbl in 2025, and 122$/bbl by 2030. Table 62 IEA price forecast Unit 2000 2007 2010 2015 2020 2025 2030 Real terms (2007 prices) IEA crude oil imports $/barrel 33.33 69.33 100.00 100.00 110.00 116.00 122.00 Natural gas US imports $/mmBTU 4.61 6.75 12.78 13.2 14.57 15.35 16.13 European imports $/mmBTU 3.35 7.03 11.15 11.5 12.71 13.45 14.19 Japan LNG $/mmBTU 5.63 7.80 12.70 13.16 14.52 15.28 16.05 OECD steam coal $/tonne 40.06 72.84 120.00 120.00 116.67 113.33 110.00 imports Nominal terms IEA crude oil imports $/barrel 28.00 69.30 107.30 120.30 148.20 175.10 206.40 Natural gas US imports $/mmBTU 3.87 6.75 13.72 15.88 19.64 23.18 27.28 European imports $/mmBTU 2.82 7.03 11.97 13.83 17.13 20.31 24.00 Japan LNG $/mmBTU 4.73 7.80 13.63 15.83 19.56 23.08 27.16 OECD steam coal $/tonne 33.70 72.80 128.80 144.30 157.20 171.10 186.10 imports Source: IEA, 2008 World Energy Outlook, Table 1.4 101 We note that oil and LNG price definitions used in forecasts differ for different sources. Sri Lanka: Environmental Issues in the Power Sector 131 ECA, RMA and ERM Fuel price forecasts The oil price forecast is considerably higher than that of the World Bank: the Bank’s 2009 Global economic prospects report102 proposes $75/bbl as the long term crude oil price (at constant 2008 prices). This is based on the proposition that the long-run marginal cost will be set by the cost of extraction from high cost sources such as Canadian tar sands. But the critical question is whether the pace of addition of new reserves will match the inevitable increase in global oil demand once global economic growth resumes after the present recession - about which authorities differ sharply.103 The World Bank’s stated view is that . . . if the pace at which new oil reserves are discovered declines, the rising price for oil will make alternative sources of energy (including coal, natural gas, nuclear, and renewable alternatives) more competitive and induce increased conservation and technological change. Simulations suggest that if oil production fails to rise between now and 2030, oil prices might double but most of the energy shortfall would be met by increased coal and natural gas consumption, albeit at higher cost.104 At present, 75% of the crude input to the Sri Lanka refinery is Iranian Light, which trades at about $1.5/bbl lower than the World Bank average. Figure 57 compares prices of the World Bank crude oil, the OPEC reference basket (ORB)105, the Japan crude cocktail (JCC) (used for Asian LNG pricing),106 and Iranian light (which is almost identical to the ORB). 102 World Bank, Global Economic Prospects 2009: Commodities at the Crossroads, December 2009. 103These range from predictions of oil at $30-40/bbl, to those of the “peak oil� advocates who see prices returning to the 150-200$/bbl range once global economic growth resumes in 2010-2011, caused not by the speculative bubble of the 2007-2008 price boom, but by the diminishing pace of addition to new reserves and the resumption of strong economic growth in Brazil, India, and China. However, as occurred ten years ago in wake of the previous crude oil price collapse (briefly touching 10$/bbl in late 1998), predictions of yet lower prices immediately after the collapse of a market bubble are as unreliable as predictions of further increases of prices immediately before a price bubble bursts. In early 1999 The Economist Magazine predicted $5/bbl as the long run crude oil price; and at the end of July 2008 at the 140$/bbl peak, Goldman Sachs confidently forecast $200/bbl would be reached by 2009. Yet just six months later, in December 2008,the Goldman Sachs forecast for 2009 was $30/bbl – which now also seems rather unlikely given that prices have risen to around $75/bbl by June 2009. 104Global Economic Prospects 2009, op.cit., p.40 105 The new OPEC Reference Basket (ORB), implemented as of 10 September 2007, is currently made up of the following crude oils: Saharan Blend (Algeria), Girassol (Angola), Minas (Indonesia), Iran Heavy (Islamic Republic of Iran), Basra Light (Iraq), Kuwait Export (Kuwait), Es Sider (Libya), Bonny Light (Nigeria), Qatar Marine (Qatar), Arab Light (Saudi Arabia), Murban (UAE) and BCF 17 (Venezuela). 106JCC is the average price of crude oil imported to Japan as published by the Japanese customs service . An English version is published by the Petroleum Association of Japan at http://www.paj.gr.jp/english/statis.html. The JCC lags the other prices by about one month (peaking in August rather than July 2008). Sri Lanka: Environmental Issues in the Power Sector 132 ECA, RMA and ERM Fuel price forecasts Figure 57 Crude oil prices Given the wide range of uncertainty, for the modelling runs of this study we therefore examine two world energy price cases: $75/bbl, and $125/bbl (at constant 2009 prices). A5.1.2 Petroleum product prices Petroleum product prices can be derived as ratios of the oil price: as shown in Figure 58 for the case of fuel oil, the relative prices show remarkable consistency over time. The Singapore high sulphur fuel oil (HSFO) price may be taken as 0.8 of the OPEC Reference Basket. Figure 58 Relative prices: Singapore fuel oil vs. ORB The source of petroleum products (whether from Singapore or Gulf) imported into Sri Lanka is not recorded by CPC, which imports on the basis of open bids. One would expect that gasoil and fuel oil would be imported from the Gulf since Gulf prices are significantly lower than Singapore prices (Figure 59) Sri Lanka: Environmental Issues in the Power Sector 133 ECA, RMA and ERM Fuel price forecasts Figure 59 Singapore v. Gulf gasoil prices (Platts, monthly averages) However, this appears not to be the case, for as shown in Table 63 and Figure 60 and Figure 61, the CPC reported free-on-board “FOB� figures seem much closer to the Singapore than to Gulf prices. Table 63 CPC petroleum product import costs, 2008-2009 GASOIL 2008 2008 2008 2008 2008 2008 2008 2008 2008 2008 2008 2008 2009 2009 2009 2009 jan feb mar apr may jun jul aug sep oct nov dec jan feb mar apr FOB $/bbl 1 06.9 1 1 0.5 1 27 .9 1 41 .1 1 60.9 1 68.6 1 67 .5 1 33.9 1 1 9.9 86.1 7 0.7 59.6 59.0 50.5 53.1 59.1 Premium $/bbl 2.7 2.8 2.9 4.4 3.1 2.9 2.2 3.1 1 .4 -0.0 0.1 -0.0 1 .8 -0.0 0.9 2.0 FOB+premium $/bbl 1 09.6 1 1 3.3 1 30.8 1 45.4 1 63.9 1 7 1 .6 1 69.7 1 36.9 1 21 .4 86.1 7 0.8 59.6 60.8 50.5 54.1 61 .1 Singapore av erage $/bbl 1 08.9 1 1 5.0 1 30.5 1 43.4 1 61 .9 1 7 0.0 1 68.6 1 35.9 1 21 .6 90.0 7 5.1 63.0 60.2 52.9 53.3 59.1 Platts Gulf av erage $/bbl 1 02.2 1 08.3 1 23.3 1 35.6 1 55.5 1 61 .7 1 61 .4 1 26.7 1 1 3.6 7 9.0 65.0 55.4 0.0 0.0 0.0 0.0 CPC v . Platts Singap$/bbl 0.6 -1 .7 0.3 2.0 2.1 1 .6 1 .0 1 .1 -0.2 -3.9 -4.4 -3.4 0.6 -2.4 0.7 2.0 CPC v Platts Gulf $/bbl 7 .4 5.0 7 .5 9.8 8.4 9.9 8.3 1 0.3 7 .8 7 .1 5.7 4.2 60.8 50.5 54.1 61 .1 Freight $/bbl 1 .6 1 .6 1 .6 1 .7 1 .9 3.0 2.8 3.4 3.2 3.1 2.3 1 .6 1 .0 1 .3 1 .0 0.7 Insurance $/bbl 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 CIF $/bbl 111.2 115.0 132.5 147 .2 165.9 17 4.6 17 2.6 140.4 124.7 89.2 7 3.2 61.3 61.9 51.8 55.1 61.8 180CST Fueloil 2008 2008 2008 2008 2008 2008 2008 2008 2008 2008 2008 2008 2009 2009 2009 2009 jan feb mar apr may jun jul aug sep oct nov dec jan feb mar apr FOB $/bbl 7 1 .5 7 3.6 7 7 .3 83.9 91 .2 99.4 1 1 2.8 1 03.5 90.7 61 .6 37 .4 35.1 39.8 39.6 37 .8 44.7 Premium $/bbl 0.8 0.8 0.7 0.7 0.5 -0.8 -0.6 -1 .2 2.4 2.3 1 .8 3.6 5.0 6.3 2.8 2.3 FOB+premium $/bbl 7 2.3 7 4.4 7 8.1 84.5 91 .6 98.6 1 1 2.1 1 02.3 93.1 63.9 39.2 38.7 44.8 45.9 40.5 47 .0 Singapore av erage $/bbl 7 0.0 7 0.0 7 4.6 81 .0 91 .2 96.2 1 09.5 1 01 .1 88.2 60.0 36.1 34.0 40.7 40.7 38.7 45.7 Platts Gulf av erage $/bbl 66.0 66.5 7 0.5 7 6.2 85.0 89.8 1 01 .3 94.0 82.5 55.2 32.6 30.5 0.0 0.0 0.0 0.0 CPC v . Platts Singap$/bbl 2.2 4.4 3.5 3.6 0.5 2.4 2.6 1 .3 4.8 3.9 3.1 4.7 4.0 5.2 1 .8 1 .4 CPC v Platts Gulf $/bbl 6.3 8.0 7 .5 8.4 6.6 8.8 1 0.8 8.4 1 0.5 8.7 6.6 8.1 44.8 45.9 40.5 47 .0 Freight $/bbl 1 .8 1 .8 1 .9 1 .9 2.2 3.4 3.2 3.8 3.7 3.5 2.6 1 .8 1 .2 1 .5 1 .1 0.8 Insurance $/bbl 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 CIF $/bbl 7 4.2 7 6.3 80.0 86.6 93.9 102.0 115.4 106.2 96.9 67 .5 42.0 40.6 46.0 47 .4 41.7 47 .9 Source: CPC Sri Lanka: Environmental Issues in the Power Sector 134 ECA, RMA and ERM Fuel price forecasts Figure 60 Sri Lanka gasoil costs, fob Source: CPC Figure 61 Sri Lanka fuel oil costs, fob Source: CPC It is possible that a strict sulphur specification increases costs over the standard quotations: as shown in Figure 62, the lower the sulphur content, the higher the price. Similarly, 180 cst 2% sulphur fuel oil typically commands a 6-8$/bbl premium over 380 cst high sulphur fuel oil (HSFO). It would not seem reasonable that products would be imported from Singapore, given the significant fob price differential, and we have not sighted the tender documents issued by CPC. This requires further explanation by CPC. Sri Lanka: Environmental Issues in the Power Sector 135 ECA, RMA and ERM Fuel price forecasts Figure 62 Gasoil price v. sulphur content Source: Platt’s Oilgram, Asia Product Price Assessments, Singapore: 29 April 2009 Freight for petroleum products Sri Lanka imports its fossil fuels for power generation over long distances, and the transportation costs are significant. In general one may observe that freight costs rise disproportionately to the fob cost: when oil prices are high, freight costs tend to be high, also as an increasing percentage of fob cost. As shown in the case of gasoil imports over the past 16 months (Figure 63), at the peak of the oil price surge in 2008 freight accounted for over 3% of the fob price, falling back to 1.1% of fob by April 2009. Fuel oil import costs are somewhat higher, both as $/bbl, and as a percentage of the FOB cost (reaching a peak of 7% in November 2008). Figure 63 Freight costs for gasoil and fuel oil imports Source: CPC It is unclear why the freight costs for fuel oil are so much higher than for gasoil: the only immediate explanation is that fuel oil volumes are quite small compared to gasoil (in 2007, CPC imported 1,321million tonnes of autodiesel, compared to 191,000 tonnes of fuel oil). Normally one would expect freight for “dirty� cargoes (crude and heavy Sri Lanka: Environmental Issues in the Power Sector 136 ECA, RMA and ERM Fuel price forecasts fuel oil) to be lower than for “clean� cargoes (other petroleum products). This also needs to be clarified with CPC. The cif prices for gasoil and fuel oil are therefore as shown in Table 64. Table 64 CIF prices for gasoil and fuel oil Crudeoil, 2008 prices $/bbl 75 125 at 2009 prices $/bbl 76.7 127.9 Singapore fuel oil fraction of crudeoil 0.81 0.81 price $/bbl 62.15 103.58 freight, insurance [ ] 2.00% 4.00% $/bbl 1.24 4.14 cif $/bbl 63.4 107.7 Singapore gasoil fraction of crudeoil 1.24 1.24 price $/bbl 93 155 Freight, insurance [ ] 1.3% 3.0% $/bbl 1.2 4.7 cif $/bbl 94.2 159.7 A5.1.3 Coal prices Coal prices fob Figure 64 shows the long term historical monthly prices of South African coal (fob Richards Bay, 6,000 kcal/kg), and Australian coal (fob Newcastle 6,300 kcal/kg GAR)107. Prices are Platt’s benchmark for 90-day forward contracts, average of the monthly assessments. For 107 Australian coal fob Newcastle, the Platt’s assessments differ little from the widely cited NEWC index, published weekly by the GlobalCoal exchange. Sri Lanka: Environmental Issues in the Power Sector 137 ECA, RMA and ERM Fuel price forecasts Figure 64 Coal prices Indonesian coal might be a candidate (Figure 65), though the Government of Indonesia has announced that exports should not be expanded further. The lower grades of Indonesian coal would need to be blended with other coals. 108 Figure 65 Export coal prices in the Asia Pacific region Coal transportation There are significant uncertainties associated with the cost of coal freight, In part these are associated with the costs of transhipment at west coast locations, in part by the type of vessel required (Trincomalee locations could accommodate Cape size vessels), and in part by the source of coal. Coal freight analyses in the Asia-Pacific market tend to be focused on trade between Australia, China and Indonesia (the main exporters) with 108Coals of lower heat value trade for less than what can be accounted for by heat value, as is illustrated by Indonesian coal: in the first quarter of 2009, so-called “Indonesian performance� coal, at 5,900 Kcal/kg (no blending needed), traded at an average of $69.90/tonne fob Kalimanthan, whereas the more abundant Indonesian 5,000 Kcal/kg grade traded at $55.17/tonne.108 If heat value were the dominant determinant, then the 5,000 Kcal/kg grade would be priced at $59.15/tonne, $4.00/tonne more than the actual price. Sri Lanka: Environmental Issues in the Power Sector 138 ECA, RMA and ERM Fuel price forecasts Japan and South Korea. Table 65 gives an indication of relative freight costs in early 2009. Table 65 Freight cost (Panamax, 60,000tonne size) $/tonne Australia (Newcastle) Japan 9.49 Australia South Korea 10.00 China (Qingqandao) Japan 4.43 China South Korea 3.32 Indonesia(Kalimanthan Japan 7.37 ) Indonesia India 6.92 Indonesia South Korea 6.12 Source: Argus Coal Daily International, 16 February 2009 Although freight costs are subject to their own market conditions, there is a strong correlation with the level of coal prices: freight rates at the peak of the coal price boom in 2008 were as much as double the early 2009 rates. With the gradual increases in coal prices one may assume somewhat higher rates would prevail, on average over the planning horizon. No information on the transportation component is available from the recent tender for coal to the west coast coal project. We therefore make the following assumptions: coal power plants at Trincomalee would be supplied by Capesize vessels (>100,000 tonne), with a total cost of freight and unloading from Australia of 14$/tonne ($12/tonne freight plus $2/tonne unloading/handling). West coast sites would be supplied by Panamax vessels at $14/tonne plus $9.00/tonne transhipment/handling). A5.1.4 LNG prices Figure 66 shows recent LNG prices: given that most LNG import contracts are tied to crude oil (in the case of Japan to the JCC), LNG prices rose steadily in 2007-2008: given the three month lag against the JCC, the LNG price peaked in October 2008. Sri Lanka: Environmental Issues in the Power Sector 139 ECA, RMA and ERM Fuel price forecasts Figure 66 LNG prices, 2007-2009 Opinions about the future evolution of LNG prices, now that oil has fallen back to $50- 75/bbl, vary widely. A number of new projects are due to come on stream in the next two years, so prices may remain low until 2012-2013: several new trains in Qatar will boost capacity by some 40%, so as demand falls with the deepening of the global recession, in the short term the sellers market of 2008 will become a buyer’s market. The relative price of coal and LNG to crude oil (on a BTU basis) have undergone significant changes over the past 10 years. For most of the 1990s, the Australian export price of coal was between 40-50% of the crude oil price. This fell to 20% in 2000, and has since been in the range of 20-35% of the crude oil price, reaching 40% only briefly at the peak of the commodities boom in 2008 (Figure 67). Figure 67 Relative prices for LNG and coal A similar shift in the relative price of LNG has also occurred: between 1992 and 2001, the LNG price was at or slightly above crude oil parity; but since 2002, the average price has fallen significantly, and since 2005 has been between 60-70%. Sri Lanka: Environmental Issues in the Power Sector 140 ECA, RMA and ERM Fuel price forecasts The IEA expectations of relative prices is shown in Figure 68: the relative coal price drifts down from 27% to 21% of the oil price by 2030, and Japan LNG remaining roughly at its current relative price of around 52%. Figure 68 IEA forecast of relative prices Source: IEA 2008 World Energy Outlook, Figure 1.5 In the case of LNG, the decline relative to the oil price follows from the general form of contract, which have pricing formulas that that take the form a+b[JCC] over some range of JCC price, with a further adjustment (the “s curve� adjustment) designed to soften the impact of low oil prices on the seller, and soften the impact of higher prices on the buyer. Following the IEA forecast, the long term LNG price is 76% of the oil price (in BTU terms). Under this assumption, the Japan cif price for 75$/bbl oil is $10.1/mmBTU (or 9.6/mmBTU cif Sri Lanka), and for the high oil $16.9/mmBTU, or $16.4/mmBTU cif Sri Lanka). Needless to say, from a long-term historical perspective, the IEA assumption of LNG at 75% of the oil parity price seems optimistic, and any LNG project faces a risk of price escalation over the longer term. Sri Lanka: Environmental Issues in the Power Sector 141 ECA, RMA and ERM Definitions of cases used in the analysis A6 Definitions of cases used in the analysis The fourteen variants to the reference case that were analysed in the study are defined below. A6.1 Policy cases Case 2: The LNG-forced Case This case examines the outcomes when LNG power plants are forced into the generation expansion plan. This forcing was required because the reference case least cost plan did not select the LNG option, in spite of the terminal investments not being included in the plant costs109. However, there is a widespread perception that LNG- based power plants will result in greater total benefits when their environmental benefits, in terms of lower emissions of SOx and particulates along with the absence of any solid waste, are considered. To examine whether this was the case, LNG-based CCGT technology was forced into the plan after the presently committed coal-fired power plants were built (3x300 MW at Puttalam and 2x250 MW at Trincomalee were considered to be committed). Case 3: Medium-sized hydropower projects forced The hydropower project list of CEB consists of four candidate power plants not chosen in the reference case plan. These include Uma Oya (150 MW), Broadlands (35 MW), Moragolla (27 MW) and Ging Ganga (49 MW). However, in a study on environmental assessments of the power sector, it is essential that candidates with lower or no emissions are included in the plan, and the impacts on the attributes quantified. These projects were thus forced into the plan from 2014-2015, and the plan was re-optimised to examine the impacts. Case 4: NCRE Forced The reference case (as well as all the other cases) had only the existing NCRE capacity (156 MW, 469.8 GWh/year) as committed, with no further NCRE developments input to the model. NCRE was thus forced in such that its contribution to total energy dispatched from the generating system reached 10% by 2015. This level was then sustained until the end of the plan through an annual NCRE injection after 2015. The NCRE scenario is described in more detail in Section 7.7 of the Main Report. Case 5: Minimum impacts Cases 2, 3 and 4 may be considered to be those alternatives that would provide minimum impacts to the environment by way of lower emissions (excluding a DSM scenario which is separately considered). This case is a combination of these such that 109LNG terminal investment and related costs were not included in the input information to WASP, but the reference case plan rejected the LNG candidate. Sri Lanka: Environmental Issues in the Power Sector 142 ECA, RMA and ERM Definitions of cases used in the analysis all the policy initiatives – forcing of LNG, forcing of small and medium hydro and forcing of NCRE - applied simultaneously. Case 6: Coal after Trincomalee to be supercritical The reference case provided for both sub-critical and supercritical coal-fired power plants to be selected. In the reference case, the only constraint imposed was that the 600 MW supercritical coal-fired generating units were not allowed to be built before the system peak demand exceeded 4,000 MW110. The reference case did not select the super-critical generating units until year 2021 and continued to build sub-critical units in Trincomalee and elsewhere even after 2021. This indicates that super-critical units do not have a significant impact on the cost attribute. In this case, development of coal- fired power generation after the on-going 3x300 MW at Puttalam and 2x250 MW development at Trincomalee was forced to be 600 MW supercritical units, ignoring the critical impacts they may have on power system stability and reliability, and perhaps economics. Case 7: No coal power plants beyond the present commitments Beyond the currently committed coal-fired plants of Puttalam and Trincomalee, no further coal-fired power plants (neither sub-critical nor super-critical) are allowed to be built. The supply gap is to be bridged with any of the oil or gas fired options presented to the model. Case 8: Pumped storage power plants The reference case required the development of a number of coal-fired power plants. From about year 2020 onwards, it is seen that some coal-fired power plants (especially the subcritical plants and the Puttalam plants) cannot be loaded to their full annual capacity factor because of the pattern of Sri Lanka’s power system load. Accordingly, some coal-fired power plants would be part-loaded at times of lower demand or may even enter a daily or weekly cycling mode. One of the options to correct this situation of part-loading or cycling base load units is to build a pumped-storage power plant. This case explores the impact of this option. Case 9: DSM intervention Sri Lanka’s system peak demand occurs during the evening and lasts for approximately three hours. Demand at this time is dominated by household lighting and television, along with street lighting. As explained in Section 5.10 of the main Report, CFLs have been popularised in Sri Lanka through several mechanisms, both CEB assisted and otherwise. Sri Lanka Sustainable Energy Authority (SEA) has begun introducing mandatory labelling of appliances for energy efficiency, and CFLs have 110This study assumed that a 600 MW (gross) supercritical generating unit may be added to thh generating system from year 2017, when the system forecast peak demand exceeds 4,000 MW. No specific steady-state and dynamic stability studies were conducted to arrive at this conclusion, and this should be studied further before CEB makes any decision to build generating units as large as 600 MW. Sri Lanka: Environmental Issues in the Power Sector 143 ECA, RMA and ERM Definitions of cases used in the analysis already been included into the labelling regime, which should improve the quality of CFLs in the market and its contribution to improving the load profile of the country. The DSM case in the study is limited to further intervention in relation to CFLs and a prohibition on the sale of incandescent bulbs so that incandescent bulbs would gradually be phased out over time. A6.2 Sensitivities around the reference case Case 10: Sensitivity to demand forecast The demand forecast used in this study was based on an econometric model developed using past data, with a subsequent correction in the first few years to reflect the near- term stagnation of electricity demand due to the global economic slowdown. This forecast resulted in a lower expected absolute demand relative to the CEB’s forecast through to 2012. The current widespread belief, however, is that demand growth in the near-term will exceed the present forecasts of CEB (and therefore would also exceed the Consultant’s forecast used in developing the reference case expansion plan of the study). Therefore, it is necessary to examine the outcome if demand growth accelerates beyond the forecast in this study towards present expectations of accelerated growth. Case 11: Higher fuel prices The reference case plan was developed based on a constant (in real 2009 USD) crude oil price of USD 75/bbl (called EIPS1). For the reasons described in Section A5.1.1, an alternative forecast based on a constant (real 2009 USD) crude oil price of USD 125/bbl was also developed (called EIPS2) with corresponding increases in the coal and gas prices. Case 12: Fuel prices escalate in real terms As described in the preceding case (Case 11: Higher fuel prices), Cases 1 through 10 were based on constant crude oil prices (USD 75 /bbl) in real terms (2009 USD). Case 11 is also a constant (2009 USD) crude oil price but at 125 USD/bbl. In Case 12 by contrast, the crude oil price is allowed to escalate in real terms from USD 75/bbl to USD125/bbl over the period 2009 to 2028. Other fuel prices correspondingly gradually rise over this period. Case 13: Lower discount rates Sri Lanka uses a real discount rate of 10% for all costs and benefits of the generating system. This is considered to be a relatively high discount rate, which may place projects with heavy investments, which typically have a long economic life, at a disadvantage. Typical examples are large/medium hydropower plants, LNG terminals and coal-fired power plants. In this case, the real discount rate is lowered from 10% to 6%, and the plan re-optimised to examine the impacts. Sri Lanka: Environmental Issues in the Power Sector 144 ECA, RMA and ERM Definitions of cases used in the analysis A6.3 Additional case combinations Case 14: NCRE forced along with fuel price escalation The NCRE scenario (Case 4) was examined under a constant fuel price scenario. When fuel prices escalate, especially under the pricing policy currently adopted for NCRE (and described in Section 7.7 of the main Report), there will be positive benefits to the power generation costs. To examine these benefits, this case raises the crude oil prices from 75 USD/bbl to 125 USD/bbl by 2020 (which is a higher rate of increase than assumed in Case 12), and continues at this same trend through the end of the planning window in 2028. Case 15: Maximum DSM case Here the study returns to examine how the benefits of the reference case plan can be maximised by combining two cases previously studied – pumped storage (Case 8) and DSM (Case 9). Thus, in this case, pumped storage power plants are allowed and a DSM program is forced in to examine the overall benefits of such a program and to fully utilise the investments that are on-going and planned for coal-fired power generation. Sri Lanka: Environmental Issues in the Power Sector 145 ECA, RMA and ERM Technology options not considered A7 Technology options not considered The following three technology options were considered but not included in the detailed analysis. A7.1 LPG LPG has been mentioned as a possible fuel for power generation. This would be a very expensive option indeed, and need not be considered. In 2007, the reported cif price of LPG by CPC was 835$/tonne,111 compared to an average posted price of 617$/tonne FOB ARAMCO. Shipment costs are high, and the cif price in Sri Lanka exceeds that of gasoil. Even ignoring shipment costs, LPG would be more expensive than LNG. The proposition that LPG would be used for large-scale power generation is therefore not credible, and not considered further in this study. Figure 69 LPG v. other fuels A7.2 Nuclear Nuclear power is subject to significant scale economies, and for units presently commercially available, the minimum unit size is around 1,000 MW.112 The Sri Lanka system will not be able to absorb so large a unit for at least 25-30 years. There is much discussion about the development of a new generation of small (250-500 MW) units, which are under development in many countries based on a wide variety of new design concepts.113 However, the costs of such small units – not yet commercially 111 Sri Lanka Energy database, based on CPC data 112In a recent review of nuclear power costs (World Nuclear Association, The Economics of Nuclear Power, November 2008), all the units for which cost estimates are reported involve units in the range of 1,080MW to 1,350MW: the typical project currently under consideration is 2 x 1,100MW. For a complete description of these new design concepts, including those based on thorium cycles and 113 advanced breeder reactors, see e.g. www.world-nuclear. org/info/inf08.html. Sri Lanka: Environmental Issues in the Power Sector 146 ECA, RMA and ERM Technology options not considered available - are subject to large uncertainties.114 Indeed, the track record of capital cost overruns in the nuclear industry is very poor, in part because of lengthy construction delays (notably in the US).115 With regard to current costs, as of mid 2009, according to the MIT study on nuclear power116 there are 44 plants under construction around the world in 12 countries, principally China, India, Korea, and Russia.117 Although reliable cost information is hard to come by, estimates in the recent literature vary from $2,000/kW to $10,000/kW. Some of this variation is explained by financial costs. With a 5 to 6 year construction time, IDC can substantially increase overnight costs. For example, the MIT study estimates overnight costs at $4,000/kW, but when IDC is added, the cost increases to $5,400 /kW.118 Late 2008 cost estimates for US utilities are 4,924$/kW (Duke Energy, overnight) to 7,833$/kW, including financial costs (TVA Bellafonte).119 Reported costs for Chinese nuclear plants are much lower, in the range of $1,400- 1,800/kW for overnight costs for the nuclear EPC (i.e., without site costs, cooling system etc).120 Furthermore, whether a country has nuclear fuel resources (uranium, thorium) has little bearing on its nuclear fuel costs. Absent fuel processing capability, even countries with good resources are exposed to the international market for nuclear fuel. Most forecasts envisage significant increases in fuel costs (Figure 70), particularly if nuclear power sees a resurgence consequent to climate change concerns. 114 There are few estimates of costs for this new generation of small nuclear units. However, given the lack of scale economies, even with advanced materials and design it is quite unlikely that their cost would be much lower than the large units on a $/kW basis. 115Finland’s effort to build the world’s first new generation nuclear reactor at Olkiluoto is now over 2 years behind schedule after beginning in 2005, and construction cost estimates have already overrun by at least one billion euro. 116 MIT, 2009 Update of the 2003 Report Future of Nuclear Power, Cambridge, Mass., 2009 117According to the 2009 MIT report, the forty four plants under construction are: China (11), Russia (8), India (6), Korea (5), Bulgaria (2), Taiwan (2), Ukraine (2), Japan (2), Argentina (1), Finland (1), France (1), Iran (1), Pakistan (1), and the United States (refurbishment, 1). 118Assuming six year construction period with six equal mid-year disbursements, and a weighted cost of capital of 10%. 119 World Nuclear Association, The Economics of Nuclear Power, November 2008. 120 Ibid., p.12. Sri Lanka: Environmental Issues in the Power Sector 147 ECA, RMA and ERM Technology options not considered Figure 70 Nuclear fuel costs Source: E.Kee Nuclear fuel future, CRA Corporation, The infeasibility of nuclear for Sri Lanka is easily illustrated through the calculation of screening curves. Assuming an overnight cost of $4,500 and a six year construction period with a 10% cost of capital, the completed cost would be $6,084/kW.121 If a constant nuclear fuel price of $0.5/mmBTU (cif) is assumed together with a fuel cost of $0.5/mmBTU, and a net heat rate of 10,450 BTU/kWh,122 nuclear costs per kWh are as shown alongside those of alternative coal options in Figure 71. 121 Assuming six equal mid-year disbursements over the construction period. 122The average heat rate reported by EIA for nuclear projects in the US is 10488 BTU/kWh. The 2003 MIT study assumes 10,400BTU/kWh Sri Lanka: Environmental Issues in the Power Sector 148 ECA, RMA and ERM Technology options not considered Figure 71 Screening curve: nuclear These estimates of nuclear power costs are undoubtedly on the low side. First, the actual weighed average cost of capital (WACC) may well be higher given the risk premium that investors will attach to nuclear energy. Some recent estimates in the US use WACC of as high as 14.5%.123 Second, this assumes no real escalation in nuclear fuel costs. That the estimates here are conservative only strengthens the case for not considering nuclear as a generation option. A7.3 Other clean coal options (Fluidized bed combustion, IGCC) Clean coal options were evaluated in the 2001 World Bank study124, with the conclusion that the application of clean coal technology does not appear to be warranted for Sri Lanka. This conclusion remains unchanged today. The technologies that are at, or close to, commercial availability -- such as atmospheric fluidised bed combustion (AFBC), or circulating fluidized bed (CFB) -- are most appropriate at mine- mouth plants using low quality coals (and hence their potential application in India and China). They do have the advantage of being available in small unit sizes (220MW CFB units are being built in Vietnam for low grade anthracite).125 However, as Sri Lanka has no indigenous fossil resources, and thus must import coal over relatively long distances, the economic rationale for application of CFB/AFC is absent. Other 123 see Craig Severance, Business risks and the cost of new nuclear power, January 2009. 124 SLEPTA, op.cit., Section 2. 125 The 2 x 220MW Mao Khe project will burn anthracite wastes. Sri Lanka: Environmental Issues in the Power Sector 149 ECA, RMA and ERM Technology options not considered clean coal technologies (such as IGCC) are simply not commercially available (and again Sri Lanka power system’s small size makes them unsuitable). Sri Lanka: Environmental Issues in the Power Sector 150 ECA, RMA and ERM Codes used in diagrams A8 Codes used in diagrams The Table below identifies the codes used in the diagrams to describe the plant types. Table 66 Codes used in diagrams to describe plant types Code Description Full Load (MW, net) CGT 35 35 MW Simple-cycle gas turbine 34.7 CGT 75 75 MW Simple-cycle gas turbine 74.3 CGT 105 105 MW Simple-cycle gas turbine 104.0 CC HFO Combined-cycle gas turbine burning heavy fuel oil 270.2 CC DSL Combined-cycle gas turbine burning distillate fuel 291.0 CC LNG Combined-cycle gas turbine burning natural gas (LNG) 291.0 COL Sub Coal-fired steam plant, subcritical technology 285.1 COL Sup Coal-fired steam plant, supercritical technology 552.0 Sri Lanka: Environmental Issues in the Power Sector 151 ECA, RMA and ERM Summary of the results of the cases A9 Summary of the results of the cases Table 67 provides a summary of the case definitions and the resulting cost attributes. Cost adjustments were required to account for several assumptions and approximations made. These included: adjustment for the costs of NCRE presently existing in the system, the costs of which were not included in the planning studies; and the costs of the LNG terminal were not included in the studies (owing to the terminal costs being shared between a number of power plants). Sri Lanka: Environmental Issues in the Power Sector 152 ECA, RMA and ERM Summary of the results of the cases Table 67 Summary of results and cost attributes with and without adjustments NPV of the Adjusted NPV PV of energy Cost change Adjustments to Levelised Cost Policy option/scenario plan (USD Adjustments to NPV of the plan dispatched from reference NPV (USD m) (UScts/kWh) m) (USD m) (GWh) case 1 Reference case 8,990.0 Add existing NCRE costs 238.5 9,228.4 154,945 5.96 0.0% Changes from the reference case LNG included or forced, 9,940.7 Add LNG terminal costs 781.4 10,722.1 154,945 6.92 16.2% 2 after Trincomalee 500 MW Medium-sized 9,109.6 Add existing NCRE costs 238.5 9,348.1 154,945 6.03 1.3% 3 hydropower projects (forced) 8,230.6 Add NCRE economic 1,695 9,925.7 154,945 6.41 7.6% 4 NCRE forced costs 9,004.4 Add NCRE economic 2,133 11,137.6 154,945 7.19 20.7% 5 combination of 2,3,4 costs Latter coal after 9,008.0 Add existing NCRE costs 238.5 9,246.5 154,945 5.97 0.2% 6 Trincomalee 500 MW forced as supercritical No coal power plants built 9,961.3 Add existing NCRE costs 238.5 10,199.8 154,945 6.58 10.5% 7 beyond the present commitments Pumped storage power 8,966.3 Add existing NCRE costs 238.5 9,204.8 154,945 5.94 -0.3% 8 plant option 8,623.1 Add existing NCRE costs 555.9 9,179.0 151,326 6.07 1.8% 9 DSM intervention + DSM program costs (CFL) Sensitivity studies on the reference case 10 Higher demand forecast 10,494.4 Add existing NCRE costs 238.5 10,732.9 172,702 6.21 4.3% Sri Lanka: Environmental Issues in the Power Sector 153 ECA, RMA and ERM Summary of the results of the cases NPV of the Adjusted NPV PV of energy Cost change Adjustments to Levelised Cost Policy option/scenario plan (USD Adjustments to NPV of the plan dispatched from reference NPV (USD m) (UScts/kWh) m) (USD m) (GWh) case 11 Higher fuel prices 12,899.8 Add existing NCRE costs 238.5 13,138.3 154,945 8.48 42.4% Fuel prices escalate in real 10,620.4 Add existing NCRE costs 238.5 10,858.9 154,945 7.01 17.7% 12 terms 13 Lower discount rate 12,031.1 Add existing NCRE costs 294.2 12,325.3 227,896 5.41 -9.2% Sensitivity studies on NCRE forced case (4) NCRE Forced with fuel 11,174.9 Add existing NCRE costs 1,695 12,870.0 154,945 8.31 39.5% 14 price escalation Maximum load profile improvement case Pumped storage power 8,597.7 Add existing NCRE costs 556 9,153.7 151,326 6.05 1.6% 15 plant and DSM + DSM program costs intervention (CFL) Sri Lanka: Environmental Issues in the Power Sector 154 ECA, RMA and ERM Detailed outputs from the model for the 15 cases A10 Detailed outputs from the model for the 15 cases The capacity and energy balance, and fuel consumption of each case studied is given in this annex. The 15 cases are as follows: Case number Case name 1 Baseline 2 LNG 3 Medium sized hydro 4 Non-conventional renewable energy (NCRE) 5 Green 6 Forced supercritical 7 No coal 8 Pumped storage 9 Demand-side management 10 High demand 11 Higher fuel prices 12 Real fuel price escalation 13 Low discount rate 14 NCRE plus real fuel price escalation 15 Pumped storage plus demand-side management Sri Lanka: Environmental Issues in the Power Sector 155 ECA, RMA and ERM Detailed outputs from the model for the 15 cases Case 1: Capacity Balance in MW Case 1 Base Case 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 Existing and Committed Hydro plants Hydro1 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 Hydro2 � � � 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 New Hydro Plants Hydro3 Hydro4 Hydro Total 1,205.0 1,205.0 1,205.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 Existing and Committed Thermal plants GTSM Small Gas Turbines 80.0 80.0 � � � � � � � � � � � � � � � � � � DSP Diesel Sapugaskanda 69.6 69.6 69.6 69.6 � � � � � � � � � � � � � � � � DSPX Diesel Sapugaskanda�Extension 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 � � � � GT7 Gas Turbine 7 114.2 114.2 114.2 114.2 114.2 114.2 114.2 114.2 114.2 � � � � � � � � � � � DLDL Lakdhanavi Diesel 22.5 22.5 22.5 22.5 � � � � � � � � � � � � � � � � DAPL Asia Power Diesel 49.0 49.0 49.0 49.0 49.0 49.0 49.0 49.0 49.0 � � � � � � � � � � � CCKP Kelanitissa Combined Cycle 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 CAES AES Combined Cycle 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 � � � � � DCPL Colombo Power Diesel 60.0 60.0 60.0 60.0 60.0 60.0 � � � � � � � � � � � � � � DHOR Horana Diesel 20.0 20.0 20.0 20.0 � � � � � � � � � � � � � � � � DMAT Matara Diesel 20.0 20.0 20.0 � � � � � � � � � � � � � � � � � DPUT Puttalam Diesel 100.0 100.0 100.0 100.0 100.0 100.0 � � � � � � � � � � � � � � DEMB Embilipitiya Diesel 100.0 100.0 100.0 100.0 100.0 100.0 � � � � � � � � � � � � � � GTKW Kerawalapitiya Gas Turbine 180.0 � � � � � � � � � � � � � � � � � � � CCKW Kerawalapitiya Combined Cycle � 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 CPUT Coal Puttalam � � 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 NCRE Existing and New RENW Renewables 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 New Thermal Power Plants GT1 Gas turbine 1 � � � 34.7 104.1 104.1 104.1 104.1 104.1 104.1 104.1 104.1 104.1 104.1 104.1 104.1 104.1 138.8 138.8 138.8 GT2 Gas turbine 2 � � � � � � � � � � � � � � � � � � � � GT3 Gas turbine 3 � � � 208.0 208.0 208.0 208.0 208.0 208.0 208.0 208.0 208.0 208.0 208.0 208.0 208.0 416.0 416.0 520.0 CTRC Coal Trinco � � � � � � 570.2 1,140.4 1,425.5 1,710.6 1,995.7 2,280.8 2,280.8 2,280.8 2,280.8 2,280.8 2,280.8 2,280.8 2,280.8 2,280.8 CCHF Combined Cycle Heavy Fuel � � � � � � � � � � � � � � � � � � � � CCDL Combined Cycle Diesel � � � � � � � � � � � � � � � � � � � � CCLN Combined Cycle LNG � � � � � � � � � � � � � � � � � � � � COSB Coal�Subcritical � � � � � 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 855.3 COSP Coal�Supercritical � � � � � � � � � � � � 552.0 552.0 1,104.0 1,656.0 2,208.0 2,208.0 2,760.0 2,760.0 PUMP Pumped Storage (generation) � � � � � � � � � � � � � � � � � � � � Thermal Total 1,209.6 1,299.6 1,504.7 1,519.4 1,684.7 2,254.9 2,565.1 3,135.3 3,420.4 3,542.3 3,827.4 4,112.5 4,664.5 4,664.5 5,216.5 5,605.5 6,087.9 6,330.6 6,882.6 7,271.7 Grand Total 2,570.6 2,660.6 2,865.7 3,030.4 3,195.7 3,765.9 4,076.1 4,646.3 4,931.4 5,053.3 5,338.4 5,623.5 6,175.5 6,175.5 6,727.5 7,116.5 7,598.9 7,841.6 8,393.6 8,782.7 Forecast Peak Demand 1,948.6 2,135.7 2,332.1 2,544.3 2,761.8 2,997.9 3,242.0 3,508.6 3,790.0 4,070.2 4,356.4 4,666.7 4,997.2 5,341.0 5,689.8 6,056.0 6,432.1 6,841.6 7,264.4 7,739.1 Reserve Margin 32% 25% 23% 19% 16% 26% 26% 32% 30% 24% 23% 21% 24% 16% 18% 18% 18% 15% 16% 13% Sri Lanka: Environmental Issues in the Power Sector 156 ECA, RMA and ERM Detailed outputs from the model for the 15 cases Case 2: Capacity Balance in MW Case 2 LNG Forced 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 Existing and Committed Hydro plants Hydro1 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 Hydro2 � � � 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 New Hydro Plants Hydro3 Hydro4 Hydro Total 1,205.0 1,205.0 1,205.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 Existing and Committed Thermal plants GTSM Small Gas Turbines 80.0 80.0 � � � � � � � � � � � � � � � � � � DSP Diesel Sapugaskanda 69.6 69.6 69.6 69.6 � � � � � � � � � � � � � � � � DSPX Diesel Sapugaskanda�Extension 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 � � � � GT7 Gas Turbine 7 114.2 114.2 114.2 114.2 114.2 114.2 114.2 114.2 114.2 � � � � � � � � � � � DLDL Lakdhanavi Diesel 22.5 22.5 22.5 22.5 � � � � � � � � � � � � � � � � DAPL Asia Power Diesel 49.0 49.0 49.0 49.0 49.0 49.0 49.0 49.0 49.0 � � � � � � � � � � � CCKP Kelanitissa Combined Cycle 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 CAES AES Combined Cycle 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 � � � � � DCPL Colombo Power Diesel 60.0 60.0 60.0 60.0 60.0 60.0 � � � � � � � � � � � � � � DHOR Horana Diesel 20.0 20.0 20.0 20.0 � � � � � � � � � � � � � � � � DMAT Matara Diesel 20.0 20.0 20.0 � � � � � � � � � � � � � � � � � DPUT Puttalam Diesel 100.0 100.0 100.0 100.0 100.0 100.0 � � � � � � � � � � � � � � DEMB Embilipitiya Diesel 100.0 100.0 100.0 100.0 100.0 100.0 � � � � � � � � � � � � � � GTKW Kerawalapitiya Gas Turbine 180.0 � � � � � � � � � � � � � � � � � � � CCKW Kerawalapitiya Combined Cycle � 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 CPUT Coal Puttalam � � 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 NCRE Existing a � RENW Renewables 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 New Thermal P � GT1 Gas turbine 1 � � � 34.7 104.1 104.1 104.1 104.1 104.1 104.1 104.1 104.1 104.1 104.1 104.1 104.1 104.1 104.1 138.8 138.8 GT2 Gas turbine 2 � � � � � � � � � � � � 74.3 74.3 74.3 74.3 222.9 222.9 222.9 222.9 GT3 Gas turbine 3 � � � � 208.0 208.0 208.0 208.0 208.0 208.0 208.0 208.0 208.0 312.0 416.0 416.0 416.0 416.0 416.0 416.0 CTRC Coal Trinco � � � � � 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 CCHF Combined Cycle Heavy Fuel � � � � � � � � � � � � � � � � � � � � CCDL Combined Cycle Diesel � � � � � � � � � � � � � � � � � � � � CCLN Combined Cycle LNG � � � � � � � � 582.0 873.0 1,164.0 1,455.0 1,746.0 2,037.0 2,328.0 2,910.0 3,201.0 3,783.0 4,074.0 4,656.0 COSB Coal�Subcritical � � � � � 285.1 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 COSP Coal�Supercritical � � � � � � � � � � � � � � � � � � � � PUMP Pumped Storage (generation) � � � � � � � � � � � � � � � � � � � � Thermal Total 1,209.6 1,299.6 1,504.7 1,519.4 1,684.7 2,540.0 2,565.1 2,565.1 3,147.1 3,274.9 3,565.9 3,856.9 4,222.2 4,617.2 5,012.2 5,431.2 5,801.2 6,383.2 6,708.9 7,290.9 Grand Total 2,570.6 2,660.6 2,865.7 3,030.4 3,195.7 4,051.0 4,076.1 4,076.1 4,658.1 4,785.9 5,076.9 5,367.9 5,733.2 6,128.2 6,523.2 6,942.2 7,312.2 7,894.2 8,219.9 8,801.9 Forecast Peak Demand 1,948.6 2,135.7 2,332.1 2,544.3 2,761.8 2,997.9 3,242.0 3,508.6 3,790.0 4,070.2 4,356.4 4,666.7 4,997.2 5,341.0 5,689.8 6,056.0 6,432.1 6,841.6 7,264.4 7,739.1 Reserve Margin 32% 25% 23% 19% 16% 35% 26% 16% 23% 18% 17% 15% 15% 15% 15% 15% 14% 15% 13% 14% Sri Lanka: Environmental Issues in the Power Sector 157 ECA, RMA and ERM Detailed outputs from the model for the 15 cases Case 3: Capacity Balance in MW Case 3 Hydro Forced 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 Existing and Committed Hydro plants Hydro1 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 Hydro2 � � � 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 New Hydro Plants Hydro3 � � � � � 62.0 62.0 62.0 62.0 62.0 62.0 62.0 62.0 62.0 62.0 62.0 62.0 62.0 62.0 62.0 Hydro4 � � � � � � 199.0 199.0 199.0 199.0 199.0 199.0 199.0 199.0 199.0 199.0 199.0 199.0 199.0 199.0 Hydro Total 1,205.0 1,205.0 1,205.0 1,355.0 1,355.0 1,417.0 1,616.0 1,616.0 1,616.0 1,616.0 1,616.0 1,616.0 1,616.0 1,616.0 1,616.0 1,616.0 1,616.0 1,616.0 1,616.0 1,616.0 Existing and Committed Thermal plants GTSM Small Gas Turbines 80.0 80.0 � � � � � � � � � � � � � � � � � � DSP Diesel Sapugaskanda 69.6 69.6 69.6 69.6 � � � � � � � � � � � � � � � � DSPX Diesel Sapugaskanda�Extension 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 � � � � GT7 Gas Turbine 7 114.2 114.2 114.2 114.2 114.2 114.2 114.2 114.2 114.2 � � � � � � � � � � � DLDL Lakdhanavi Diesel 22.5 22.5 22.5 22.5 � � � � � � � � � � � � � � � � DAPL Asia Power Diesel 49.0 49.0 49.0 49.0 49.0 49.0 49.0 49.0 49.0 � � � � � � � � � � � CCKP Kelanitissa Combined Cycle 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 CAES AES Combined Cycle 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 � � � � � DCPL Colombo Power Diesel 60.0 60.0 60.0 60.0 60.0 60.0 � � � � � � � � � � � � � � DHOR Horana Diesel 20.0 20.0 20.0 20.0 � � � � � � � � � � � � � � � � DMAT Matara Diesel 20.0 20.0 20.0 � � � � � � � � � � � � � � � � � DPUT Puttalam Diesel 100.0 100.0 100.0 100.0 100.0 100.0 � � � � � � � � � � � � � � DEMB Embilipitiya Diesel 100.0 100.0 100.0 100.0 100.0 100.0 � � � � � � � � � � � � � � GTKW Kerawalapitiya Gas Turbine 180.0 � � � � � � � � � � � � � � � � � � � CCKW Kerawalapitiya Combined Cycle � 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 CPUT Coal Puttalam � � 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 NCRE Existing and New RENW Renewables 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 New Thermal Power Plants GT1 Gas turbine 1 � � � � � � � � � � � � � � 138.8 138.8 138.8 138.8 138.8 138.8 GT2 Gas turbine 2 � � � � � � � � � � � � � � � � � � 148.6 148.6 GT3 Gas turbine 3 � � � � 312.0 312.0 312.0 312.0 312.0 312.0 312.0 312.0 312.0 312.0 312.0 312.0 312.0 312.0 416.0 416.0 CTRC Coal Trinco � � � � � � 570.2 855.3 1,140.4 1,425.5 1,710.6 1,995.7 2,280.8 2,280.8 2,280.8 2,280.8 2,280.8 2,280.8 2,280.8 2,280.8 CCHF Combined Cycle Heavy Fuel � � � � � CCDL Combined Cycle Diesel � � � � � � � � � � � � � � � � � � � � CCLN Combined Cycle LNG � � � � � � � � � � � � � � � � � � � � COSB Coal�Subcritical � � � � � 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 COSP Coal�Supercritical � � � � � � � � � � � � � 552.0 552.0 1,104.0 1,656.0 2,208.0 2,208.0 2,760.0 PUMP Pumped Storage (generation) � � � � � � � � � � � � � � � � � � � � Thermal Total 1,209.6 1,299.6 1,504.7 1,484.7 1,684.6 2,254.8 2,565.0 2,850.1 3,135.2 3,257.1 3,542.2 3,827.3 4,112.4 4,664.4 4,803.2 5,192.2 5,674.6 6,226.6 6,479.2 7,031.2 Grand Total 2,570.6 2,660.6 2,865.7 2,995.7 3,195.6 3,827.8 4,337.0 4,622.1 4,907.2 5,029.1 5,314.2 5,599.3 5,884.4 6,436.4 6,575.2 6,964.2 7,446.6 7,998.6 8,251.2 8,803.2 Forecast Peak Demand 1,948.6 2,135.7 2,332.1 2,544.3 2,761.8 2,997.9 3,242.0 3,508.6 3,790.0 4,070.2 4,356.4 4,666.7 4,997.2 5,341.0 5,689.8 6,056.0 6,432.1 6,841.6 7,264.4 7,739.1 Reserve Margin 32% 25% 23% 18% 16% 28% 34% 32% 29% 24% 22% 20% 18% 21% 16% 15% 16% 17% 14% 14% Sri Lanka: Environmental Issues in the Power Sector 158 ECA, RMA and ERM Detailed outputs from the model for the 15 cases Case 4: Capacity Balance in MW Case 4 NCRE Target 10% by 2015 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 Existing and Committed Hydro plants Hydro1 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 Hydro2 � � � 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 New Hydro Plants Hydro3 Hydro4 Hydro Total 1,205.0 1,205.0 1,205.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 Existing and Committed Thermal plants GTSM Small Gas Turbines 80.0 80.0 � � � � � � � � � � � � � � � � � � DSP Diesel Sapugaskanda 69.6 69.6 69.6 69.6 � � � � � � � � � � � � � � � � DSPX Diesel Sapugaskanda�Extension 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 � � � � GT7 Gas Turbine 7 114.2 114.2 114.2 114.2 114.2 114.2 114.2 114.2 114.2 � � � � � � � � � � � DLDL Lakdhanavi Diesel 22.5 22.5 22.5 22.5 � � � � � � � � � � � � � � � � DAPL Asia Power Diesel 49.0 49.0 49.0 49.0 49.0 49.0 49.0 49.0 49.0 � � � � � � � � � � � CCKP Kelanitissa Combined Cycle 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 CAES AES Combined Cycle 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 � � � � � DCPL Colombo Power Diesel 60.0 60.0 60.0 60.0 60.0 60.0 � � � � � � � � � � � � � � DHOR Horana Diesel 20.0 20.0 20.0 20.0 � � � � � � � � � � � � � � � � DMAT Matara Diesel 20.0 20.0 20.0 � � � � � � � � � � � � � � � � � DPUT Puttalam Diesel 100.0 100.0 100.0 100.0 100.0 100.0 � � � � � � � � � � � � � � DEMB Embilipitiya Diesel 100.0 100.0 100.0 100.0 100.0 100.0 � � � � � � � � � � � � � � GTKW Kerawalapitiya Gas Turbine 180.0 � � � � � � � � � � � � � � � � � � � CCKW Kerawalapitiya Combined Cycle � 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 CPUT Coal Puttalam � � 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 NCRE Existing and New RENW Renewables 182.0 215.0 258.0 300.0 373.0 455.0 548.0 596.0 634.0 672.0 710.0 748.0 805.0 862.0 919.0 976.0 1033.0 1090.0 1147.0 1204.0 New Thermal Power Plants GT1 Gas turbine 1 � � � � 138.8 138.8 138.8 138.8 138.8 138.8 138.8 138.8 138.8 138.8 138.8 208.2 208.2 208.2 208.2 208.2 GT2 Gas turbine 2 � � � � � � � � � � � � � � � � � � � � GT3 Gas turbine 3 � � � � 104.0 104.0 104.0 104.0 104.0 104.0 104.0 104.0 104.0 104.0 208.0 208.0 208.0 208.0 312.0 312.0 CTRC Coal Trinco � � � � � � 570.2 855.3 1,140.4 1,425.5 1,710.6 1,995.7 2,280.8 2,280.8 2,280.8 2,280.8 2,280.8 2,280.8 2,280.8 2,280.8 CCHF Combined Cycle Heavy Fuel � � � � � � � � � � � � � � � � � � � � CCDL Combined Cycle Diesel � � � � � � � � � � � � � � � � � � � � CCLN Combined Cycle LNG � � � � � � � � � � � � � � � � � � � � COSB Coal�Subcritical � � � � � 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 855.3 855.3 1,140.4 COSP Coal�Supercritical � � � � � � � � � � � � � 552.0 552.0 1,104.0 1,656.0 1,656.0 1,656.0 2,208.0 PUMP Pumped Storage (generation) � � � � � � � � � � � � � � � � � � � � Thermal Total 1,209.6 1,299.6 1,504.7 1,484.7 1,615.4 2,185.6 2,495.8 2,780.9 3,066.0 3,187.9 3,473.0 3,758.1 4,043.2 4,595.2 4,699.2 5,157.6 5,640.0 5,925.1 6,029.1 6,866.2 Grand Total 2,596.6 2,719.6 2,967.7 3,139.7 3,343.4 3,995.6 4,398.8 4,731.9 5,055.0 5,214.9 5,538.0 5,861.1 6,203.2 6,812.2 6,973.2 7,488.6 8,028.0 8,370.1 8,531.1 9,425.2 Forecast Peak Demand 1,948.6 2,135.7 2,332.1 2,544.3 2,761.8 2,997.9 3,242.0 3,508.6 3,790.0 4,070.2 4,356.4 4,666.7 4,997.2 5,341.0 5,689.8 6,056.0 6,432.1 6,841.6 7,264.4 7,739.1 Reserve Margin 33% 27% 27% 23% 21% 33% 36% 35% 33% 28% 27% 26% 24% 28% 23% 24% 25% 22% 17% 22% Sri Lanka: Environmental Issues in the Power Sector 159 ECA, RMA and ERM Detailed outputs from the model for the 15 cases Case 5: Capacity Balance in MW Case 5 LNG, Hydro and NCRE forced 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 Existing and Committed Hydro plants Hydro1 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 Hydro2 � � � 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 New Hydro Plants Hydro3 � � � � � 62.0 62.0 62.0 62.0 62.0 62.0 62.0 62.0 62.0 62.0 62.0 62.0 62.0 62.0 62.0 Hydro4 � � � � � � 199.0 199.0 199.0 199.0 199.0 199.0 199.0 199.0 199.0 199.0 199.0 199.0 199.0 199.0 Hydro Total 1,205.0 1,205.0 1,205.0 1,355.0 1,355.0 1,417.0 1,616.0 1,616.0 1,616.0 1,616.0 1,616.0 1,616.0 1,616.0 1,616.0 1,616.0 1,616.0 1,616.0 1,616.0 1,616.0 1,616.0 Existing and Committed Thermal plants GTSM Small Gas Turbines 80.0 80.0 � � � � � � � � � � � � � � � � � � DSP Diesel Sapugaskanda 69.6 69.6 69.6 69.6 � � � � � � � � � � � � � � � � DSPX Diesel Sapugaskanda�Extension 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 � � � � GT7 Gas Turbine 7 114.2 114.2 114.2 114.2 114.2 114.2 114.2 114.2 114.2 � � � � � � � � � � � DLDL Lakdhanavi Diesel 22.5 22.5 22.5 22.5 � � � � � � � � � � � � � � � � DAPL Asia Power Diesel 49.0 49.0 49.0 49.0 49.0 49.0 49.0 49.0 49.0 � � � � � � � � � � � CCKP Kelanitissa Combined Cycle 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 CAES AES Combined Cycle 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 � � � � � DCPL Colombo Power Diesel 60.0 60.0 60.0 60.0 60.0 60.0 � � � � � � � � � � � � � � DHOR Horana Diesel 20.0 20.0 20.0 20.0 � � � � � � � � � � � � � � � � DMAT Matara Diesel 20.0 20.0 20.0 � � � � � � � � � � � � � � � � � DPUT Puttalam Diesel 100.0 100.0 100.0 100.0 100.0 100.0 � � � � � � � � � � � � � � DEMB Embilipitiya Diesel 100.0 100.0 100.0 100.0 100.0 100.0 � � � � � � � � � � � � � � GTKW Kerawalapitiya Gas Turbine 180.0 � � � � � � � � � � � � � � � � � � � CCKW Kerawalapitiya Combined Cycle � 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 CPUT Coal Puttalam � � 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 NCRE Existing and New RENW Renewables 182.0 215.0 258.0 300.0 373.0 455.0 548.0 596.0 634.0 672.0 710.0 748.0 805.0 862.0 919.0 976.0 1033.0 1090.0 1147.0 1204.0 New Thermal Power Plants GT1 Gas turbine 1 � � � � 138.8 138.8 138.8 138.8 138.8 138.8 138.8 138.8 138.8 138.8 138.8 138.8 138.8 138.8 138.8 138.8 GT2 Gas turbine 2 � � � � � � � � � � � � � � � � � 74.3 74.3 74.3 GT3 Gas turbine 3 � � � � 104.0 104.0 104.0 104.0 104.0 104.0 104.0 104.0 104.0 104.0 104.0 104.0 208.0 312.0 416.0 624.0 CTRC Coal Trinco � � � � � 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 CCHF Combined Cycle Heavy Fuel � � � � � � � � � � � � � � � � � � � � CCDL Combined Cycle Diesel � � � � � � � � � � � � � � � � � � � � CCLN Combined Cycle LNG � � � � � � � � 291.0 582.0 873.0 1,164.0 1,455.0 1,746.0 2,037.0 2,619.0 2,910.0 3,201.0 3,492.0 3,783.0 COSB Coal�Subcritical � � � � � 285.1 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 COSP Coal�Supercritical � � � � � � � � � � � � � � � � � � � � PUMP Pumped Storage (generation) � � � � � � � � � � � � � � � � � � � � Thermal Total 1,209.6 1,299.6 1,504.7 1,484.7 1,615.4 2,470.7 2,495.8 2,495.8 2,786.8 2,914.6 3,205.6 3,496.6 3,787.6 4,078.6 4,369.6 4,788.6 5,114.0 5,583.3 5,978.3 6,477.3 Grand Total 2,596.6 2,719.6 2,967.7 3,139.7 3,343.4 4,342.7 4,659.8 4,707.8 5,036.8 5,202.6 5,531.6 5,860.6 6,208.6 6,556.6 6,904.6 7,380.6 7,763.0 8,289.3 8,741.3 9,297.3 Forecast Peak Demand 1,948.6 2,135.7 2,332.1 2,544.3 2,761.8 2,997.9 3,242.0 3,508.6 3,790.0 4,070.2 4,356.4 4,666.7 4,997.2 5,341.0 5,689.8 6,056.0 6,432.1 6,841.6 7,264.4 7,739.1 Reserve Margin 33% 27% 27% 23% 21% 45% 44% 34% 33% 28% 27% 26% 24% 23% 21% 22% 21% 21% 20% 20% Sri Lanka: Environmental Issues in the Power Sector 160 ECA, RMA and ERM Detailed outputs from the model for the 15 cases Case 6: Capacity Balance in MW Case 6 Early Supercritical Coal 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 Existing and Committed Hydro plants Hydro1 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 Hydro2 � � � 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 New Hydro Plants Hydro3 Hydro4 Hydro Total 1,205.0 1,205.0 1,205.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 Existing and Committed Thermal plants GTSM Small Gas Turbines 80.0 80.0 � � � � � � � � � � � � � � � � � � DSP Diesel Sapugaskanda 69.6 69.6 69.6 69.6 � � � � � � � � � � � � � � � � DSPX Diesel Sapugaskanda�Extension 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 � � � � GT7 Gas Turbine 7 114.2 114.2 114.2 114.2 114.2 114.2 114.2 114.2 114.2 � � � � � � � � � � � DLDL Lakdhanavi Diesel 22.5 22.5 22.5 22.5 � � � � � � � � � � � � � � � � DAPL Asia Power Diesel 49.0 49.0 49.0 49.0 49.0 49.0 49.0 49.0 49.0 � � � � � � � � � � � CCKP Kelanitissa Combined Cycle 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 CAES AES Combined Cycle 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 � � � � � DCPL Colombo Power Diesel 60.0 60.0 60.0 60.0 60.0 60.0 � � � � � � � � � � � � � � DHOR Horana Diesel 20.0 20.0 20.0 20.0 � � � � � � � � � � � � � � � � DMAT Matara Diesel 20.0 20.0 20.0 � � � � � � � � � � � � � � � � � DPUT Puttalam Diesel 100.0 100.0 100.0 100.0 100.0 100.0 � � � � � � � � � � � � � � DEMB Embilipitiya Diesel 100.0 100.0 100.0 100.0 100.0 100.0 � � � � � � � � � � � � � � GTKW Kerawalapitiya Gas Turbine 180.0 � � � � � � � � � � � � � � � � � � � CCKW Kerawalapitiya Combined Cycle � 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 CPUT Coal Puttalam � � 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 NCRE Existing and New RENW Renewables 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 New Thermal Power Plants GT1 Gas turbine 1 � � � 34.7 173.5 173.5 173.5 173.5 173.5 173.5 173.5 173.5 173.5 173.5 173.5 208.2 208.2 208.2 208.2 208.2 GT2 Gas turbine 2 � � � � 148.6 148.6 148.6 148.6 148.6 148.6 148.6 148.6 148.6 148.6 148.6 148.6 148.6 148.6 148.6 148.6 GT3 Gas turbine 3 � � � � � � � � � � � � � � � � � � � � CTRC Coal Trinco � � � � � � 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 CCHF Combined Cycle Heavy Fuel � � � � � � � � � � � � � � � � � � 270.2 270.2 CCDL Combined Cycle Diesel � � � � � � � � � � � � � � � 291.0 291.0 291.0 291.0 291.0 CCLN Combined Cycle LNG � � � � � � � � � � � � � � � � � � � � COSB Coal�Subcritical � � � � � 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 COSP Coal�Supercritical � � � � � � � � 552.0 1,104.0 1,104.0 1,656.0 2,208.0 2,208.0 2,760.0 2,760.0 3,312.0 3,864.0 3,864.0 4,416.0 PUMP Pumped Storage (generation) � � � � � � � � � � � � � � � � � � � � Thermal Total 1,209.6 1,299.6 1,504.7 1,519.4 1,694.7 2,264.9 2,575.1 2,575.1 3,127.1 3,515.9 3,515.9 4,067.9 4,619.9 4,619.9 5,171.9 5,334.6 5,817.0 6,369.0 6,639.2 7,191.2 Grand Total 2,570.6 2,660.6 2,865.7 3,030.4 3,205.7 3,775.9 4,086.1 4,086.1 4,638.1 5,026.9 5,026.9 5,578.9 6,130.9 6,130.9 6,682.9 6,845.6 7,328.0 7,880.0 8,150.2 8,702.2 Forecast Peak Demand 1,948.6 2,135.7 2,332.1 2,544.3 2,761.8 2,997.9 3,242.0 3,508.6 3,790.0 4,070.2 4,356.4 4,666.7 4,997.2 5,341.0 5,689.8 6,056.0 6,432.1 6,841.6 7,264.4 7,739.1 Reserve Margin 32% 25% 23% 19% 16% 26% 26% 16% 22% 24% 15% 20% 23% 15% 17% 13% 14% 15% 12% 12% Sri Lanka: Environmental Issues in the Power Sector 161 ECA, RMA and ERM Detailed outputs from the model for the 15 cases Case 7: Capacity Balance in MW Case 7 No coal beyond Trinco Commitments 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 Existing and Committed Hydro plants Hydro1 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 Hydro2 � � � 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 New Hydro Plants Hydro3 Hydro4 Hydro Total 1,205.0 1,205.0 1,205.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 Existing and Committed Thermal plants GTSM Small Gas Turbines 80.0 80.0 � � � � � � � � � � � � � � � � � � DSP Diesel Sapugaskanda 69.6 69.6 69.6 69.6 � � � � � � � � � � � � � � � � DSPX Diesel Sapugaskanda�Extension 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 � � � � GT7 Gas Turbine 7 114.2 114.2 114.2 114.2 114.2 114.2 114.2 114.2 114.2 � � � � � � � � � � � DLDL Lakdhanavi Diesel 22.5 22.5 22.5 22.5 � � � � � � � � � � � � � � � � DAPL Asia Power Diesel 49.0 49.0 49.0 49.0 49.0 49.0 49.0 49.0 49.0 � � � � � � � � � � � CCKP Kelanitissa Combined Cycle 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 CAES AES Combined Cycle 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 � � � � � DCPL Colombo Power Diesel 60.0 60.0 60.0 60.0 60.0 60.0 � � � � � � � � � � � � � � DHOR Horana Diesel 20.0 20.0 20.0 20.0 � � � � � � � � � � � � � � � � DMAT Matara Diesel 20.0 20.0 20.0 � � � � � � � � � � � � � � � � � DPUT Puttalam Diesel 100.0 100.0 100.0 100.0 100.0 100.0 � � � � � � � � � � � � � � DEMB Embilipitiya Diesel 100.0 100.0 100.0 100.0 100.0 100.0 � � � � � � � � � � � � � � GTKW Kerawalapitiya Gas Turbine 180.0 � � � � � � � � � � � � � � � � � � � CCKW Kerawalapitiya Combined Cycle � 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 CPUT Coal Puttalam � � 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 NCRE Existing and New RENW Renewables 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 New Thermal Power Plants GT1 Gas turbine 1 � � � 34.7 312.3 312.3 312.3 312.3 312.3 312.3 312.3 312.3 312.3 312.3 312.3 312.3 312.3 312.3 312.3 312.3 GT2 Gas turbine 2 � � � � � � � � � � � � � � � � � � 74.3 74.3 GT3 Gas turbine 3 � � � � � � � � � � � � 104.0 208.0 312.0 312.0 416.0 416.0 416.0 416.0 CTRC Coal Trinco � � � � � � 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 CCHF Combined Cycle Heavy Fuel � � � � � � � � � � � � � � � � � � � � CCDL Combined Cycle Diesel � � � � � � � � � � � � � � � � � � � � CCLN Combined Cycle LNG � � � � � 291.0 291.0 291.0 582.0 873.0 1,164.0 1,455.0 1,746.0 2,037.0 2,328.0 2,910.0 3,201.0 3,783.0 4,074.0 4,365.0 COSB Coal�Subcritical � � � � � 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 COSP Coal�Supercritical � � � � � � � � � � � � � � � � � � � � PUMP Pumped Storage (generation) � � � � � � � � � � � � � � � � � � � � Thermal Total 1,209.6 1,299.6 1,504.7 1,519.4 1,684.9 2,546.1 2,856.3 2,856.3 3,147.3 3,275.1 3,566.1 3,857.1 4,252.1 4,647.1 5,042.1 5,461.1 5,786.5 6,368.5 6,733.8 7,024.8 Grand Total 2,570.6 2,660.6 2,865.7 3,030.4 3,195.9 4,057.1 4,367.3 4,367.3 4,658.3 4,786.1 5,077.1 5,368.1 5,763.1 6,158.1 6,553.1 6,972.1 7,297.5 7,879.5 8,244.8 8,535.8 Forecast Peak Demand 1,948.6 2,135.7 2,332.1 2,544.3 2,761.8 2,997.9 3,242.0 3,508.6 3,790.0 4,070.2 4,356.4 4,666.7 4,997.2 5,341.0 5,689.8 6,056.0 6,432.1 6,841.6 7,264.4 7,739.1 Reserve Margin 32% 25% 23% 19% 16% 35% 35% 24% 23% 18% 17% 15% 15% 15% 15% 15% 13% 15% 13% 10% Sri Lanka: Environmental Issues in the Power Sector 162 ECA, RMA and ERM Detailed outputs from the model for the 15 cases Case 8: Capacity Balance in MW Case 8 Pumped storage plants allowed 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 Existing and Committed Hydro plants Hydro1 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 Hydro2 � � � 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 New Hydro Plants Hydro3 Hydro4 Hydro Total 1,205.0 1,205.0 1,205.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 Existing and Committed Thermal plants GTSM Small Gas Turbines 80.0 80.0 � � � � � � � � � � � � � � � � � � DSP Diesel Sapugaskanda 69.6 69.6 69.6 69.6 � � � � � � � � � � � � � � � � DSPX Diesel Sapugaskanda�Extension 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 � � � � GT7 Gas Turbine 7 114.2 114.2 114.2 114.2 114.2 114.2 114.2 114.2 114.2 � � � � � � � � � � � DLDL Lakdhanavi Diesel 22.5 22.5 22.5 22.5 � � � � � � � � � � � � � � � � DAPL Asia Power Diesel 49.0 49.0 49.0 49.0 49.0 49.0 49.0 49.0 49.0 � � � � � � � � � � � CCKP Kelanitissa Combined Cycle 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 CAES AES Combined Cycle 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 � � � � � DCPL Colombo Power Diesel 60.0 60.0 60.0 60.0 60.0 60.0 � � � � � � � � � � � � � � DHOR Horana Diesel 20.0 20.0 20.0 20.0 � � � � � � � � � � � � � � � � DMAT Matara Diesel 20.0 20.0 20.0 � � � � � � � � � � � � � � � � � DPUT Puttalam Diesel 100.0 100.0 100.0 100.0 100.0 100.0 � � � � � � � � � � � � � � DEMB Embilipitiya Diesel 100.0 100.0 100.0 100.0 100.0 100.0 � � � � � � � � � � � � � � GTKW Kerawalapitiya Gas Turbine 180.0 � � � � � � � � � � � � � � � � � � � CCKW Kerawalapitiya Combined Cycle � 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 CPUT Coal Puttalam � � 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 NCRE Existing and New RENW Renewables 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 New Thermal Power Plants GT1 Gas turbine 1 � � � 34.7 104.1 104.1 104.1 104.1 104.1 104.1 104.1 104.1 104.1 104.1 104.1 104.1 138.8 138.8 173.5 173.5 GT2 Gas turbine 2 � � � � � � � � � � � � � � � � � � � � GT3 Gas turbine 3 � � � � 208.0 208.0 208.0 208.0 208.0 208.0 208.0 208.0 208.0 208.0 208.0 208.0 208.0 208.0 208.0 208.0 CTRC Coal Trinco � � � � � � 570.2 1,140.4 1,425.5 1,710.6 1,995.7 2,280.8 2,280.8 2,280.8 2,280.8 2,280.8 2,280.8 2,280.8 2,280.8 2,280.8 CCHF Combined Cycle Heavy Fuel � � � � � � � � � � � � � � � � � CCDL Combined Cycle Diesel � � � � � � � � � � � � � � � � � CCLN Combined Cycle LNG � � � � � � � � � � � � � � � � � COSB Coal�Subcritical � � � � � 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 COSP Coal�Supercritical � � � � � � � � � � � � 552.0 552.0 1,104.0 1,656.0 1,656.0 2,208.0 2,208.0 2,760.0 PUMP Pumped Storage (generation) � � � � � � � � � � � � � � � � 250.0 250.0 500.0 500.0 Thermal Total 1,209.6 1,299.6 1,504.7 1,519.4 1,684.7 2,254.9 2,565.1 3,135.3 3,420.4 3,542.3 3,827.4 4,112.5 4,664.5 4,664.5 5,216.5 5,605.5 5,820.6 6,372.6 6,657.3 7,209.3 Grand Total 2,570.6 2,660.6 2,865.7 3,030.4 3,195.7 3,765.9 4,076.1 4,646.3 4,931.4 5,053.3 5,338.4 5,623.5 6,175.5 6,175.5 6,727.5 7,116.5 7,331.6 7,883.6 8,168.3 8,720.3 Forecast Peak Demand 1,948.6 2,135.7 2,332.1 2,544.3 2,761.8 2,997.9 3,242.0 3,508.6 3,790.0 4,070.2 4,356.4 4,666.7 4,997.2 5,341.0 5,689.8 6,056.0 6,432.1 6,841.6 7,264.4 7,739.1 Reserve Margin 32% 25% 23% 19% 16% 26% 26% 32% 30% 24% 23% 21% 24% 16% 18% 18% 14% 15% 12% 13% Sri Lanka: Environmental Issues in the Power Sector 163 ECA, RMA and ERM Detailed outputs from the model for the 15 cases Case 9: Capacity Balance in MW Case 9 DSM intervention 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 Existing and Committed Hydro plants Hydro1 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 Hydro2 � � � 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 New Hydro Plants Hydro3 Hydro4 Hydro Total 1,205.0 1,205.0 1,205.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 Existing and Committed Thermal plants GTSM Small Gas Turbines 80.0 80.0 � � � � � � � � � � � � � � � � � � DSP Diesel Sapugaskanda 69.6 69.6 69.6 69.6 � � � � � � � � � � � � � � � � DSPX Diesel Sapugaskanda�Extension 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 � � � � GT7 Gas Turbine 7 114.2 114.2 114.2 114.2 114.2 114.2 114.2 114.2 114.2 � � � � � � � � � � � DLDL Lakdhanavi Diesel 22.5 22.5 22.5 22.5 � � � � � � � � � � � � � � � � DAPL Asia Power Diesel 49.0 49.0 49.0 49.0 49.0 49.0 49.0 49.0 49.0 � � � � � � � � � � � CCKP Kelanitissa Combined Cycle 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 CAES AES Combined Cycle 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 � � � � � DCPL Colombo Power Diesel 60.0 60.0 60.0 60.0 60.0 60.0 � � � � � � � � � � � � � � DHOR Horana Diesel 20.0 20.0 20.0 20.0 � � � � � � � � � � � � � � � � DMAT Matara Diesel 20.0 20.0 20.0 � � � � � � � � � � � � � � � � � DPUT Puttalam Diesel 100.0 100.0 100.0 100.0 100.0 100.0 � � � � � � � � � � � � � � DEMB Embilipitiya Diesel 100.0 100.0 100.0 100.0 100.0 100.0 � � � � � � � � � � � � � � GTKW Kerawalapitiya Gas Turbine 180.0 � � � � � � � � � � � � � � � � � � � CCKW Kerawalapitiya Combined Cycle � 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 CPUT Coal Puttalam � � 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 NCRE Existing and New RENW Renewables 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 New Thermal Power Plants GT1 Gas turbine 1 � � � � � � � � � � � � 35.0 35.0 35.0 70.0 70.0 70.0 70.0 70.0 GT2 Gas turbine 2 � � � � � � � � � � � � � � � � � � � GT3 Gas turbine 3 � � � � 210.0 210.0 210.0 210.0 210.0 210.0 210.0 210.0 210.0 210.0 210.0 210.0 210.0 210.0 210.0 210.0 CTRC Coal Trinco � � � � � � 570.2 1,140.4 1,425.5 1,710.6 1,995.7 2,280.8 2,280.8 2,280.8 2,280.8 2,280.8 2,280.8 2,280.8 2,280.8 2,280.8 CCHF Combined Cycle Heavy Fuel � � � � � � � � � � � � � � � � � � � � CCDL Combined Cycle Diesel � � � � � � � � � � � � � � � � � � � � CCLN Combined Cycle LNG � � � � � � � � � � � � � � � � � � � � COSB Coal�Subcritical � � � � � 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 COSP Coal�Supercritical � � � � � � � � � � � � � 552.0 1,104.0 1,104.0 1,656.0 2,208.0 2,760.0 2,760.0 PUMP Pumped Storage (generation) � � � � � � � � � � � � � � � � � � � � Thermal Total 1,209.6 1,299.6 1,504.7 1,484.7 1,582.6 2,152.8 2,463.0 3,033.2 3,318.3 3,440.2 3,725.3 4,010.4 4,045.4 4,597.4 5,149.4 5,021.4 5,503.8 6,055.8 6,607.8 6,607.8 Grand Total 2,570.6 2,660.6 2,865.7 2,995.7 3,093.6 3,663.8 3,974.0 4,544.2 4,829.3 4,951.2 5,236.3 5,521.4 5,556.4 6,108.4 6,660.4 6,532.4 7,014.8 7,566.8 8,118.8 8,118.8 Forecast Peak Demand 1,949.0 2,012.4 2,074.4 2,275.2 2,480.8 2,704.6 2,939.2 3,196.0 3,472.5 3,747.7 4,028.9 4,334.3 4,663.1 5,005.2 5,352.3 5,716.9 6,091.2 6,499.1 6,920.2 7,393.1 Reserve Margin 32% 32% 38% 32% 25% 35% 35% 42% 39% 32% 30% 27% 19% 22% 24% 14% 15% 16% 17% 10% Sri Lanka: Environmental Issues in the Power Sector 164 ECA, RMA and ERM Detailed outputs from the model for the 15 cases Case 10: Capacity Balance in MW Case 10 High demand forecast 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 Existing and Committed Hydro plants Hydro1 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 Hydro2 � � � 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 New Hydro Plants Hydro3 Hydro4 Hydro Total 1,205.0 1,205.0 1,205.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 Existing and Committed Thermal plants GTSM Small Gas Turbines 80.0 80.0 � � � � � � � � � � � � � � � � � � DSP Diesel Sapugaskanda 69.6 69.6 69.6 69.6 � � � � � � � � � � � � � � � � DSPX Diesel Sapugaskanda�Extension 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 � � � � GT7 Gas Turbine 7 114.2 114.2 114.2 114.2 114.2 114.2 114.2 114.2 114.2 � � � � � � � � � � � DLDL Lakdhanavi Diesel 22.5 22.5 22.5 22.5 � � � � � � � � � � � � � � � � DAPL Asia Power Diesel 49.0 49.0 49.0 49.0 49.0 49.0 49.0 49.0 49.0 � � � � � � � � � � � CCKP Kelanitissa Combined Cycle 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 CAES AES Combined Cycle 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 � � � � � DCPL Colombo Power Diesel 60.0 60.0 60.0 60.0 60.0 60.0 � � � � � � � � � � � � � � DHOR Horana Diesel 20.0 20.0 20.0 20.0 � � � � � � � � � � � � � � � � DMAT Matara Diesel 20.0 20.0 20.0 � � � � � � � � � � � � � � � � � DPUT Puttalam Diesel 100.0 100.0 100.0 100.0 100.0 100.0 � � � � � � � � � � � � � � DEMB Embilipitiya Diesel 100.0 100.0 100.0 100.0 100.0 100.0 � � � � � � � � � � � � � � GTKW Kerawalapitiya Gas Turbine 180.0 � � � � � � � � � � � � � � � � � � � CCKW Kerawalapitiya Combined Cycle � 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 CPUT Coal Puttalam � � 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 NCRE Existing and New RENW Renewables 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 New Thermal Power Plants GT1 Gas turbine1 � � � � � � � � � � � 69.4 69.4 69.4 69.4 69.4 69.4 138.8 138.8 138.8 GT2 Gas turbine2 � � � � � � � � � � � � � � � � � � � � GT3 Gas turbine 3 � � 104.0 104.0 208.0 208.0 208.0 208.0 208.0 208.0 208.0 312.0 312.0 312.0 312.0 312.0 312.0 416.0 416.0 416.0 CTRC Coal Trinco � � � � � 570.2 1,140.4 1,425.5 1,710.6 2,280.8 2,280.8 2,280.8 2,280.8 2,280.8 2,280.8 2,280.8 2,280.8 2,280.8 2,280.8 2,280.8 CCHF Combined Cycle Heavy Fuel � � � � � � � � � � � � � � � � � � � � CCDL Combined Cycle Diesel � � � � � � � � � � � � � � � � � � � � CCLN Combined Cycle LNG � � � � � � � � � � � � � � � � � � � � COSB Coal�Subcritical � � � � � 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 COSP Coal�Supercritical � � � � � � � � � � � � 552.0 1,104.0 1,656.0 2,208.0 2,760.0 2,760.0 3,312.0 3,864.0 PUMP Pumped Storage (generation) � � � � � � � � � � � � � � � � � � � � Thermal Total � 1,209.6 1,299.6 1,608.7 1,588.7 1,580.6 2,721.0 3,031.2 3,316.3 3,601.4 4,008.4 4,008.4 4,181.8 4,733.8 5,285.8 5,837.8 6,226.8 6,709.2 6,882.6 7,434.6 7,986.6 Grand Total � 2,570.6 2,660.6 2,969.7 3,099.7 3,091.6 4,232.0 4,542.2 4,827.3 5,112.4 5,519.4 5,519.4 5,692.8 6,244.8 6,796.8 7,348.8 7,737.8 8,220.2 8,393.6 8,945.6 9,497.6 Forecast Peak D � 1949.0 2189.0 2459.0 2764.0 3066.0 3381.0 3674.0 3987.0 4313.0 4636.0 4964.0 5319.0 5697.0 6090.0 6489.0 6907.0 7337.0 7805.0 8288.0 8831.0 Reserve Margin � 32% 22% 21% 12% 1% 25% 24% 21% 19% 19% 11% 7% 10% 12% 13% 12% 12% 8% 8% 8% Sri Lanka: Environmental Issues in the Power Sector 165 ECA, RMA and ERM Detailed outputs from the model for the 15 cases Case 11: Capacity Balance in MW Case 11 High fuel prices 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 Existing and Committed Hydro plants Hydro1 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 Hydro2 � � � 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 New Hydro Plants Hydro3 Hydro4 Hydro Total 1,205.0 1,205.0 1,205.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 Existing and Committed Thermal plants GTSM Small Gas Turbines 80.0 80.0 � � � � � � � � � � � � � � � � � � DSP Diesel Sapugaskanda 69.6 69.6 69.6 69.6 � � � � � � � � � � � � � � � � DSPX Diesel Sapugaskanda�Extension 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 � � � � GT7 Gas Turbine 7 114.2 114.2 114.2 114.2 114.2 114.2 114.2 114.2 114.2 � � � � � � � � � � � DLDL Lakdhanavi Diesel 22.5 22.5 22.5 22.5 � � � � � � � � � � � � � � � � DAPL Asia Power Diesel 49.0 49.0 49.0 49.0 49.0 49.0 49.0 49.0 49.0 � � � � � � � � � � � CCKP Kelanitissa Combined Cycle 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 CAES AES Combined Cycle 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 � � � � � DCPL Colombo Power Diesel 60.0 60.0 60.0 60.0 60.0 60.0 � � � � � � � � � � � � � � DHOR Horana Diesel 20.0 20.0 20.0 20.0 � � � � � � � � � � � � � � � � DMAT Matara Diesel 20.0 20.0 20.0 � � � � � � � � � � � � � � � � � DPUT Puttalam Diesel 100.0 100.0 100.0 100.0 100.0 100.0 � � � � � � � � � � � � � � DEMB Embilipitiya Diesel 100.0 100.0 100.0 100.0 100.0 100.0 � � � � � � � � � � � � � � GTKW Kerawalapitiya Gas Turbine 180.0 � � � � � � � � � � � � � � � � � � � CCKW Kerawalapitiya Combined Cycle � 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 CPUT Coal Puttalam � � 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 NCRE Existing and New RENW Renewables 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 New Thermal Power Plants GT1 Gas turbine 1 � � � 34.7 104.1 104.1 104.1 104.1 104.1 104.1 104.1 104.1 104.1 104.1 104.1 104.1 138.8 138.8 208.2 208.2 GT2 Gas turbine 2 � � � � � � � � � � � � � � � � � � � � GT3 Gas turbine 3 � � � � 208.0 208.0 208.0 208.0 208.0 208.0 208.0 208.0 208.0 208.0 208.0 208.0 208.0 208.0 208.0 208.0 CTRC Coal Trinco � � � � � � 570.2 1,140.4 1,425.5 1,710.6 1,995.7 2,280.8 2,280.8 2,280.8 2,280.8 2,280.8 2,280.8 2,280.8 2,280.8 2,280.8 CCHF Combined Cycle Heavy Fuel � � � � � � � � � � � � � � � � � � � � CCDL Combined Cycle Diesel � � � � � � � � � � � � � � � � � � � � CCLN Combined Cycle LNG � � � � � � � � � � � � � � � � � � � � COSB Coal�Subcritical � � � � � 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 855.3 855.3 1,140.4 1,140.4 COSP Coal�Supercritical � � � � � � � � � � � � 552.0 552.0 1,104.0 1,656.0 1,656.0 2,208.0 2,208.0 2,760.0 PUMP Pumped Storage (generation) � � � � � � � � � � � � � � � � � � � � Thermal Total 1,209.6 1,299.6 1,504.7 1,519.4 1,684.7 2,254.9 2,565.1 3,135.3 3,420.4 3,542.3 3,827.4 4,112.5 4,664.5 4,664.5 5,216.5 5,605.5 5,855.7 6,407.7 6,762.2 7,314.2 Grand Total 2,570.6 2,660.6 2,865.7 3,030.4 3,195.7 3,765.9 4,076.1 4,646.3 4,931.4 5,053.3 5,338.4 5,623.5 6,175.5 6,175.5 6,727.5 7,116.5 7,366.7 7,918.7 8,273.2 8,825.2 Forecast Peak Demand 1,948.6 2,135.7 2,332.1 2,544.3 2,761.8 2,997.9 3,242.0 3,508.6 3,790.0 4,070.2 4,356.4 4,666.7 4,997.2 5,341.0 5,689.8 6,056.0 6,432.1 6,841.6 7,264.4 7,739.1 Reserve Margin 32% 25% 23% 19% 16% 26% 26% 32% 30% 24% 23% 21% 24% 16% 18% 18% 15% 16% 14% 14% Sri Lanka: Environmental Issues in the Power Sector 166 ECA, RMA and ERM Detailed outputs from the model for the 15 cases Case 12: Capacity Balance in MW Case 12 Escalating fuel prices 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 Existing and Committed Hydro plants Hydro1 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 Hydro2 � � � 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 New Hydro Plants Hydro3 Hydro4 Hydro Total 1,205.0 1,205.0 1,205.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 � Existing and Committed Thermal plants GTSM Small Gas Turbines 80.0 80.0 � � � � � � � � � � � � � � � � � � DSP Diesel Sapugaskanda 69.6 69.6 69.6 69.6 � � � � � � � � � � � � � � � � DSPX Diesel Sapugaskanda�Extension 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 � � � � GT7 Gas Turbine 7 114.2 114.2 114.2 114.2 114.2 114.2 114.2 114.2 114.2 � � � � � � � � � � � DLDL Lakdhanavi Diesel 22.5 22.5 22.5 22.5 � � � � � � � � � � � � � � � � DAPL Asia Power Diesel 49.0 49.0 49.0 49.0 49.0 49.0 49.0 49.0 49.0 � � � � � � � � � � � CCKP Kelanitissa Combined Cycle 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 CAES AES Combined Cycle 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 � � � � � DCPL Colombo Power Diesel 60.0 60.0 60.0 60.0 60.0 60.0 � � � � � � � � � � � � � � DHOR Horana Diesel 20.0 20.0 20.0 20.0 � � � � � � � � � � � � � � � � DMAT Matara Diesel 20.0 20.0 20.0 � � � � � � � � � � � � � � � � � DPUT Puttalam Diesel 100.0 100.0 100.0 100.0 100.0 100.0 � � � � � � � � � � � � � � DEMB Embilipitiya Diesel 100.0 100.0 100.0 100.0 100.0 100.0 � � � � � � � � � � � � � � GTKW Kerawalapitiya Gas Turbine 180.0 � � � � � � � � � � � � � � � � � � � CCKW Kerawalapitiya Combined Cycle � 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 CPUT Coal Puttalam � � 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 NCRE Existing and New RENW Renewables 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 New Thermal Power Plants GT1 Gas turbine 1 � � � 34.7 104.1 104.1 104.1 104.1 104.1 104.1 104.1 104.1 104.1 104.1 104.1 104.1 104.1 138.8 138.8 138.8 GT2 Gas turbine 2 � � � � � � � � � � � � � � � � � 74.3 74.3 74.3 GT3 Gas turbine 3 � � � � 208.0 208.0 208.0 208.0 208.0 208.0 208.0 208.0 208.0 208.0 208.0 208.0 208.0 312.0 312.0 312.0 CTRC Coal Trinco � � � � � � 570.2 1,140.4 1,425.5 1,710.6 1,995.7 2,280.8 2,280.8 2,280.8 2,280.8 2,280.8 2,280.8 2,280.8 2,280.8 2,280.8 CCHF Combined Cycle Heavy Fuel � � � � � � � � � � � � � � � � � � � � CCDL Combined Cycle Diesel � � � � � � � � � � � � � � � � � � � � CCLN Combined Cycle LNG � � � � � � � � � � � � � � � � � � � � COSB Coal�Subcritical � � � � � 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 855.3 855.3 1,140.4 1,140.4 COSP Coal�Supercritical � � � � � � � � � � � � 552.0 552.0 1,104.0 1,656.0 2,208.0 2,208.0 2,760.0 3,312.0 PUMP Pumped Storage (generation) � � � � � � � � � � � � � � � � � � � � Thermal Total 1,209.6 1,299.6 1,504.7 1,519.4 1,684.7 2,254.9 2,565.1 3,135.3 3,420.4 3,542.3 3,827.4 4,112.5 4,664.5 4,664.5 5,216.5 5,605.5 6,373.0 6,586.0 7,423.1 7,975.1 Grand Total 2,570.6 2,660.6 2,865.7 3,030.4 3,195.7 3,765.9 4,076.1 4,646.3 4,931.4 5,053.3 5,338.4 5,623.5 6,175.5 6,175.5 6,727.5 7,116.5 7,884.0 8,097.0 8,934.1 9,486.1 Forecast Peak Demand 1,948.6 2,135.7 2,332.1 2,544.3 2,761.8 2,997.9 3,242.0 3,508.6 3,790.0 4,070.2 4,356.4 4,666.7 4,997.2 5,341.0 5,689.8 6,056.0 6,432.1 6,841.6 7,264.4 7,739.1 Reserve Margin 32% 25% 23% 19% 16% 26% 26% 32% 30% 24% 23% 21% 24% 16% 18% 18% 23% 18% 23% 23% Sri Lanka: Environmental Issues in the Power Sector 167 ECA, RMA and ERM Detailed outputs from the model for the 15 cases Case 13: Capacity Balance in MW Case 13 Lower discount rate 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 Existing and Committed Hydro plants Hydro1 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 Hydro2 � � � 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 New Hydro Plants Hydro3 � � � � � 62.0 62.0 62.0 62.0 62.0 62.0 62.0 62.0 62.0 62.0 62.0 62.0 62.0 62.0 62.0 Hydro4 � � � � � � 199.0 199.0 199.0 199.0 199.0 199.0 199.0 199.0 199.0 199.0 199.0 199.0 199.0 199.0 Hydro Total 1,205.0 1,205.0 1,205.0 1,355.0 1,355.0 1,417.0 1,616.0 1,616.0 1,616.0 1,616.0 1,616.0 1,616.0 1,616.0 1,616.0 1,616.0 1,616.0 1,616.0 1,616.0 1,616.0 1,616.0 Existing and Committed Thermal plants GTSM Small Gas Turbines 80.0 80.0 � � � � � � � � � � � � � � � � � � DSP Diesel Sapugaskanda 69.6 69.6 69.6 69.6 � � � � � � � � � � � � � � � � DSPX Diesel Sapugaskanda�Extension 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 � � � � GT7 Gas Turbine 7 114.2 114.2 114.2 114.2 114.2 114.2 114.2 114.2 114.2 � � � � � � � � � � � DLDL Lakdhanavi Diesel 22.5 22.5 22.5 22.5 � � � � � � � � � � � � � � � � DAPL Asia Power Diesel 49.0 49.0 49.0 49.0 49.0 49.0 49.0 49.0 49.0 � � � � � � � � � � � CCKP Kelanitissa Combined Cycle 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 CAES AES Combined Cycle 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 � � � � � DCPL Colombo Power Diesel 60.0 60.0 60.0 60.0 60.0 60.0 � � � � � � � � � � � � � � DHOR Horana Diesel 20.0 20.0 20.0 20.0 � � � � � � � � � � � � � � � � DMAT Matara Diesel 20.0 20.0 20.0 � � � � � � � � � � � � � � � � � DPUT Puttalam Diesel 100.0 100.0 100.0 100.0 100.0 100.0 � � � � � � � � � � � � � � DEMB Embilipitiya Diesel 100.0 100.0 100.0 100.0 100.0 100.0 � � � � � � � � � � � � � � GTKW Kerawalapitiya Gas Turbine 180.0 � � � � � � � � � � � � � � � � � � � CCKW Kerawalapitiya Combined Cycle � 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 CPUT Coal Puttalam � � 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 NCRE Existing and New RENW Renewables 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 New Thermal Power Plants GT1 Gas turbine 1 � � � � 104.1 104.1 104.1 104.1 104.1 104.1 104.1 104.1 104.1 104.1 104.1 104.1 104.1 104.1 104.1 104.1 GT2 Gas turbine 2 � � � � � � � � � � � � � � � � � � � � GT3 Gas turbine 3 � � � 104.0 208.0 208.0 208.0 208.0 208.0 208.0 208.0 208.0 208.0 208.0 208.0 208.0 208.0 208.0 208.0 208.0 CTRC Coal Trinco � � � � � � 570.2 1,140.4 1,425.5 1,710.6 1,995.7 2,280.8 2,280.8 2,280.8 2,280.8 2,280.8 2,280.8 2,280.8 2,280.8 2,280.8 CCHF Combined Cycle Heavy Fuel � � � � � � � � � � � � � � � � � � � � CCDL Combined Cycle Diesel � � � � � � � � � � � � � � � � � � � � CCLN Combined Cycle LNG � � � � � � � � � � � � � � � � � � � � COSB Coal�Subcritical � � � � � 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 855.3 855.3 1,140.4 1,140.4 COSP Coal�Supercritical � � � � � � � � � � � � 552.0 552.0 1,104.0 1,656.0 2,208.0 2,208.0 2,760.0 3,312.0 PUMP Pumped Storage (generation) � � � � � � � � � � � � � � � � � � � � Thermal Total 1,209.6 1,299.6 1,504.7 1,588.7 1,684.7 2,254.9 2,565.1 3,135.3 3,420.4 3,542.3 3,827.4 4,112.5 4,664.5 4,664.5 5,216.5 5,605.5 6,373.0 6,373.0 7,210.1 7,762.1 Grand Total 2,570.6 2,660.6 2,865.7 3,099.7 3,195.7 3,827.9 4,337.1 4,907.3 5,192.4 5,314.3 5,599.4 5,884.5 6,436.5 6,436.5 6,988.5 7,377.5 8,145.0 8,145.0 8,982.1 9,534.1 Forecast Peak Demand 1,948.6 2,135.7 2,332.1 2,544.3 2,761.8 2,997.9 3,242.0 3,508.6 3,790.0 4,070.2 4,356.4 4,666.7 4,997.2 5,341.0 5,689.8 6,056.0 6,432.1 6,841.6 7,264.4 7,739.1 Reserve Margin 32% 25% 23% 22% 16% 28% 34% 40% 37% 31% 29% 26% 29% 21% 23% 22% 27% 19% 24% 23% Sri Lanka: Environmental Issues in the Power Sector 168 ECA, RMA and ERM Detailed outputs from the model for the 15 cases Case 14: Capacity Balance in MW Case 14 NCRE forced with fuel price esc. 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 Existing and Committed Hydro plants Hydro1 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 Hydro2 � � � 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 New Hydro Plants Hydro3 Hydro4 Hydro Total 1,205.0 1,205.0 1,205.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 Existing and Committed Thermal plants GTSM Small Gas Turbines 80.0 80.0 � � � � � � � � � � � � � � � � � � DSP Diesel Sapugaskanda 69.6 69.6 69.6 69.6 � � � � � � � � � � � � � � � � DSPX Diesel Sapugaskanda�Extension 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 � � � � GT7 Gas Turbine 7 114.2 114.2 114.2 114.2 114.2 114.2 114.2 114.2 114.2 � � � � � � � � � � � DLDL Lakdhanavi Diesel 22.5 22.5 22.5 22.5 � � � � � � � � � � � � � � � � DAPL Asia Power Diesel 49.0 49.0 49.0 49.0 49.0 49.0 49.0 49.0 49.0 � � � � � � � � � � � CCKP Kelanitissa Combined Cycle 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 CAES AES Combined Cycle 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 � � � � � DCPL Colombo Power Diesel 60.0 60.0 60.0 60.0 60.0 60.0 � � � � � � � � � � � � � � DHOR Horana Diesel 20.0 20.0 20.0 20.0 � � � � � � � � � � � � � � � � DMAT Matara Diesel 20.0 20.0 20.0 � � � � � � � � � � � � � � � � � DPUT Puttalam Diesel 100.0 100.0 100.0 100.0 100.0 100.0 � � � � � � � � � � � � � � DEMB Embilipitiya Diesel 100.0 100.0 100.0 100.0 100.0 100.0 � � � � � � � � � � � � � � GTKW Kerawalapitiya Gas Turbine 180.0 � � � � � � � � � � � � � � � � � � � CCKW Kerawalapitiya Combined Cycle � 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 CPUT Coal Puttalam � � 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 NCRE Existing and New RENW Renewables 182.0 215.0 258.0 300.0 373.0 455.0 548.0 596.0 634.0 672.0 710.0 748.0 805.0 862.0 919.0 976.0 1033.0 1090.0 1147.0 1204.0 New Thermal Power Plants GT1 Gas turbine 1 � � � � 138.8 138.8 138.8 138.8 138.8 138.8 138.8 138.8 138.8 138.8 138.8 208.2 208.2 208.2 208.2 208.2 GT2 Gas turbine 2 � � � � � � � � � � � � � � � � � � � 74.3 GT3 Gas turbine 3 � � � � 104.0 104.0 104.0 104.0 104.0 104.0 104.0 104.0 104.0 208.0 208.0 208.0 208.0 208.0 208.0 208.0 CTRC Coal Trinco � � � � � � 570.2 1,140.4 1,140.4 1,425.5 1,995.7 1,995.7 2,280.8 2,280.8 2,280.8 2,280.8 2,280.8 2,280.8 2,280.8 2,280.8 CCHF Combined Cycle Heavy Fuel � � � � � � � � � � � � � � � � � � � � CCDL Combined Cycle Diesel � � � � � � � � � � � � � � � � � � � � CCLN Combined Cycle LNG � � � � � � � � � � � � � � � � � � � � COSB Coal�Subcritical � � � � � 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 1,140.4 1,425.5 1,425.5 1,710.6 1,710.6 1,995.7 COSP Coal�Supercritical � � � � � � � � � � � � � � � � 552.0 552.0 1,104.0 1,104.0 PUMP Pumped Storage (generation) � � � � � � � � � � � � � � � � � � � � Thermal Total 1,209.6 1,299.6 1,504.7 1,484.7 1,615.4 2,185.6 2,495.8 3,066.0 3,066.0 3,187.9 3,758.1 3,758.1 4,043.2 4,147.2 4,717.4 4,908.9 5,391.3 5,676.4 6,228.4 6,587.8 Grand Total 2,596.6 2,719.6 2,967.7 3,139.7 3,343.4 3,995.6 4,398.8 5,017.0 5,055.0 5,214.9 5,823.1 5,861.1 6,203.2 6,364.2 6,991.4 7,239.9 7,779.3 8,121.4 8,730.4 9,146.8 Forecast Peak Demand 1,948.6 2,135.7 2,332.1 2,544.3 2,761.8 2,997.9 3,242.0 3,508.6 3,790.0 4,070.2 4,356.4 4,666.7 4,997.2 5,341.0 5,689.8 6,056.0 6,432.1 6,841.6 7,264.4 7,739.1 Reserve Margin 33% 27% 27% 23% 21% 33% 36% 43% 33% 28% 34% 26% 24% 19% 23% 20% 21% 19% 20% 18% Sri Lanka: Environmental Issues in the Power Sector 169 ECA, RMA and ERM Detailed outputs from the model for the 15 cases Case 15: Capacity Balance in MW Case 15 Pumped storage allowed with DSM int 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 Existing and Committed Hydro plants Hydro1 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 1,205.0 Hydro2 � � � 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 New Hydro Plants Hydro3 Hydro4 Hydro Total 1,205.0 1,205.0 1,205.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 1,355.0 Existing and Committed Thermal plants GTSM Small Gas Turbines 80.0 80.0 � � � � � � � � � � � � � � � � � � DSP Diesel Sapugaskanda 69.6 69.6 69.6 69.6 � � � � � � � � � � � � � � � � DSPX Diesel Sapugaskanda�Extension 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 69.6 � � � � GT7 Gas Turbine 7 114.2 114.2 114.2 114.2 114.2 114.2 114.2 114.2 114.2 � � � � � � � � � � � DLDL Lakdhanavi Diesel 22.5 22.5 22.5 22.5 � � � � � � � � � � � � � � � � DAPL Asia Power Diesel 49.0 49.0 49.0 49.0 49.0 49.0 49.0 49.0 49.0 � � � � � � � � � � � CCKP Kelanitissa Combined Cycle 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 161.7 CAES AES Combined Cycle 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 163.0 � � � � � DCPL Colombo Power Diesel 60.0 60.0 60.0 60.0 60.0 60.0 � � � � � � � � � � � � � � DHOR Horana Diesel 20.0 20.0 20.0 20.0 � � � � � � � � � � � � � � � � DMAT Matara Diesel 20.0 20.0 20.0 � � � � � � � � � � � � � � � � � DPUT Puttalam Diesel 100.0 100.0 100.0 100.0 100.0 100.0 � � � � � � � � � � � � � � DEMB Embilipitiya Diesel 100.0 100.0 100.0 100.0 100.0 100.0 � � � � � � � � � � � � � � GTKW Kerawalapitiya Gas Turbine 180.0 � � � � � � � � � � � � � � � � � � � CCKW Kerawalapitiya Combined Cycle � 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 270.0 CPUT Coal Puttalam � � 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 285.1 NCRE Existing and New RENW Renewables 182.0 215.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 156.0 New Thermal Power Plants GT1 Gas turbine 1 � � � � � � � � � � � � 35.0 35.0 35.0 35.0 35.0 35.0 35.0 35.0 GT2 Gas turbine 2 � � � � � � � � � � � � � � � � � � � � GT3 Gas turbine 3 � � � � 210.0 210.0 210.0 210.0 210.0 210.0 210.0 210.0 210.0 210.0 210.0 210.0 210.0 210.0 210.0 210.0 CTRC Coal Trinco � � � � � � 570.2 1,140.4 1,140.4 1,425.5 1,710.6 1,710.6 2,280.8 2,280.8 2,280.8 2,280.8 2,280.8 2,280.8 2,280.8 2,280.8 CCHF Combined Cycle Heavy Fuel � � � � � � � � � � � � � � � � � � � � CCDL Combined Cycle Diesel � � � � � � � � � � � � � � � � � � � � CCLN Combined Cycle LNG � � � � � � � � � � � � � � � � � � � � COSB Coal�Subcritical � � � � � 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 570.2 COSP Coal�Supercritical � � � � � � � � � � � � � 552.0 1,104.0 1,104.0 1,656.0 1,656.0 2,208.0 2,760.0 PUMP Pumped Storage (generation) � � � � � � � � � � � � 250.0 250.0 500.0 500.0 500.0 Thermal Total 1,209.6 1,299.6 1,504.7 1,484.7 1,582.6 2,152.8 2,463.0 3,033.2 3,033.2 3,155.1 3,440.2 3,440.2 4,045.4 4,597.4 5,149.4 5,236.4 5,718.8 5,968.8 6,520.8 7,072.8 Grand Total 2,596.6 2,719.6 2,865.7 2,995.7 3,093.6 3,663.8 3,974.0 4,544.2 4,544.2 4,666.1 4,951.2 4,951.2 5,556.4 6,108.4 6,660.4 6,747.4 7,229.8 7,479.8 8,031.8 8,583.8 Forecast Peak Demand 1,949.0 2,012.4 2,074.4 2,275.2 2,480.8 2,704.6 2,939.2 3,196.0 3,472.5 3,747.7 4,028.9 4,334.3 4,663.1 5,005.2 5,352.3 5,716.9 6,091.2 6,499.1 6,920.2 7,393.1 Reserve Margin 33% 35% 38% 32% 25% 35% 35% 42% 31% 25% 23% 14% 19% 22% 24% 18% 19% 15% 16% 16% Sri Lanka: Environmental Issues in the Power Sector 170 ECA, RMA and ERM Detailed outputs from the model for the 15 cases Case 1: Energy Balance in GWh Case 1 Base Case 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 Existing and Committed Hydro plants Hydro1 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 Hydro2 � � � 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 New Hydro Plants Hydro3 Hydro4 Hydro Total 4,375.5 4,375.5 4,375.5 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 Existing and Committed Thermal plants GTSM Small Gas Turbines 1.6 5.4 � � � � � � � � � � � � � � � � � � DSP Diesel Sapugaskanda 435.4 418.7 347.1 384.3 � � � � � � � � � � � � � � � � DSPX Diesel Sapugaskanda�Extension 462.0 462.0 462.0 462.0 462.0 434.3 294.8 116.2 113.9 109.6 110.3 109.9 50.4 115.1 34.5 16.6 � � � � GT7 Gas Turbine 7 11.8 34.5 8.8 36.8 83.2 1.1 1.3 0.2 0.4 � � � � � � � � � � � DLDL Lakdhanavi Diesel 137.0 99.6 48.5 84.0 � � � � � � � � � � � � � � � � DAPL Asia Power Diesel 328.9 322.8 280.7 306.4 321.7 179.1 83.2 17.7 22.0 � � � � � � � � � � � CCKP Kelanitissa Combined Cycle 126.6 208.2 70.3 196.6 643.8 99.2 63.9 7.2 8.1 13.6 21.0 30.9 9.2 52.4 23.8 24.4 15.5 66.1 43.5 77.4 CAES AES Combined Cycle 902.6 573.6 273.4 481.1 1,047.2 323.4 221.9 34.6 41.3 66.0 66.3 88.6 25.2 129.6 55.7 � � � � � DCPL Colombo Power Diesel 417.6 388.2 299.6 348.0 403.2 195.5 � � � � � � � � � � � � � � DHOR Horana Diesel 152.8 124.9 66.2 102.1 � � � � � � � � � � � � � � � � DMAT Matara Diesel 151.2 119.3 57.4 � � � � � � � � � � � � � � � � � DPUT Puttalam Diesel 696.2 694.1 638.8 676.8 688.7 451.5 � � � � � � � � � � � � � � DEMB Embilipitiya Diesel 671.2 585.5 365.1 492.0 643.8 268.5 � � � � � � � � � � � � � � GTKW Kerawalapitiya Gas Turbine 398.4 � � � � � � � � � � � � � � � � � � � CCKW Kerawalapitiya Combined Cycle � 1,813.0 1,789.8 1,804.7 1,810.9 1,496.6 757.9 272.9 284.1 292.4 277.6 297.8 103.1 330.3 180.1 83.5 47.7 191.2 122.5 198.8 CPUT Coal Puttalam � � 2,153.5 2,153.5 2,153.5 2,153.5 2,149.6 1,997.7 1,879.4 1,756.9 1,660.5 1,571.5 1,143.6 1,435.8 1,078.0 772.0 560.4 855.6 658.3 977.6 NCRE Existing and New RENW Renewables 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 New Thermal Power Plants GT1 Gas turbine 1 � � � 3.1 20.0 0.3 0.5 0.1 0.1 0.7 1.1 2.2 0.9 6.3 3.5 4.1 2.6 7.9 5.6 8.2 GT2 Gas turbine 2 � � � � � � � � � � � � � � � � � � � � GT3 Gas turbine 3 � � � � 383.1 20.7 12.5 1.6 2.5 5.1 7.3 11.6 4.5 26.9 13.5 14.9 9.7 66.9 46.4 97.2 CTRC Coal Trinco � � � � � � 3,776.3 7,525.6 9,358.8 11,157.0 12,928.6 14,660.0 13,767.5 14,194.1 13,200.9 11,879.9 10,376.1 11,490.7 10,308.3 11,388.3 CCHF CC�Heavy Fuel � � � � � � � � � � � � � � � � � � � � CCDL CC�Diesel � � � � � � � � � � � � � � � � � � � � CCLN CC�LNG � � � � � � � � � � � � � � � � � � � � COSB Coal�Subcritical � � � � � 4,268.4 3,804.2 2,590.9 2,328.8 2,109.7 1,951.4 1,899.7 1,149.6 1,790.1 1,194.1 789.9 494.0 995.0 741.0 1,660.9 COSP Coal�Supercritical � � � � � � � � � � � � 4,169.3 4,169.3 8,338.6 12,502.5 16,604.1 16,643.1 20,679.1 20,761.8 PUMP Pumped Storage (generation) � � � � � � � � � � � � � � � � � � � � Thermal Total incl NCRE 5,363.2 6,319.5 7,330.8 8,001.1 9,130.9 10,361.6 11,635.7 13,034.4 14,509.1 15,980.7 17,493.8 19,141.9 20,893.0 22,719.7 24,592.3 26,557.4 28,579.8 30,786.2 33,074.5 35,640.0 Grand Total 9,738.7 10,695.0 11,706.3 12,797.9 13,927.7 15,158.4 16,432.5 17,831.2 19,305.9 20,777.5 22,290.6 23,938.7 25,689.8 27,516.5 29,389.1 31,354.2 33,376.6 35,583.0 37,871.3 40,436.8 Forecast demand 9,739.0 10,697.0 11,707.0 12,803.0 13,935.0 15,158.0 16,431.0 17,831.0 19,306.0 20,778.0 22,291.0 23,940.0 25,691.0 27,525.0 29,393.0 31,360.0 33,380.0 35,592.0 37,878.0 40,448.0 Unserved Energy 0.3 2.0 0.7 5.2 7.3 (0.4) (1.5) (0.2) 0.2 0.5 0.4 1.3 1.2 8.5 3.9 5.8 3.4 9.0 6.7 11.2 Sri Lanka: Environmental Issues in the Power Sector 171 ECA, RMA and ERM Detailed outputs from the model for the 15 cases Case 2: Energy Balance in GWh Case 2 LNG Forced 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 Existing and Committed Hydro plants Hydro1 � 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 Hydro2 � � � 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 New Hydro Plants Hydro3 � Hydro4 � Hydro Total 4,375.5 4,375.5 4,375.5 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 Existing and Committed Thermal plants GTSM Small Gas Turbines 1.6 5.4 � � � � � � � � � � � � � � � � � � DSP Diesel Sapugaskanda 435.4 418.7 347.1 384.3 � � � � � � � � � � � � � � � � DSPX Diesel Sapugaskanda�Extension 462.0 462.0 462.0 462.0 462.0 362.8 294.8 370.1 184.6 154.2 137.8 128.0 128.1 128.3 66.3 42.2 � � � � GT7 Gas Turbine 7 11.8 34.5 8.8 36.8 83.2 0.1 1.3 18.7 2.3 � � � � � � � � � � � DLDL Lakdhanavi Diesel 137.0 99.6 48.5 84.0 � � � � � � � � � � � � � � � � DAPL Asia Power Diesel 328.9 322.8 280.7 306.4 321.7 86.0 83.2 160.0 55.2 � � � � � � � � � � � CCKP Kelanitissa Combined Cycle 126.6 208.2 70.3 196.6 643.8 9.3 63.9 253.1 37.3 54.8 50.8 53.3 63.6 75.1 106.7 93.7 138.7 71.8 105.6 78.9 CAES AES Combined Cycle 902.6 573.6 273.4 481.1 1,047.2 87.1 221.9 473.0 124.3 149.6 139.0 138.8 152.3 172.4 201.0 � � � � � DCPL Colombo Power Diesel 417.6 388.2 299.6 348.0 403.2 86.8 � � � � � � � � � � � � � � DHOR Horana Diesel 152.8 124.9 66.2 102.1 � � � � � � � � � � � � � � � � DMAT Matara Diesel 151.2 119.3 57.4 � � � � � � � � � � � � � � � � � DPUT Puttalam Diesel 696.2 694.1 638.8 676.8 688.7 234.7 � � � � � � � � � � � � � � DEMB Embilipitiya Diesel 671.2 585.5 365.1 492.0 643.8 100.1 � � � � � � � � � � � � � � GTKW Kerawalapitiya Gas Turbine 398.4 � � � � � � � � � � � � � � � � � � � CCKW Kerawalapitiya Combined Cycle � 1,813.0 1,789.8 1,804.7 1,810.9 1,044.2 757.9 1,186.1 502.5 427.7 398.0 392.5 388.0 385.4 427.9 268.1 310.8 204.9 261.2 200.5 CPUT Coal Puttalam � � 2,153.5 2,153.5 2,153.5 2,139.8 2,149.6 2,152.7 2,153.2 2,153.4 2,153.5 2,153.5 2,153.5 2,153.5 2,153.5 2,153.5 2,153.5 2,153.5 2,153.5 2,153.5 NCRE Existing and New RENW Renewables 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 New Thermal Power Plants GT1 Gas turbine 1 � � � 3.1 20.0 0.0 0.5 6.6 1.0 3.6 4.3 5.8 5.7 5.2 5.7 6.0 6.0 3.7 8.8 7.1 GT2 Gas turbine 2 � � � � � � � � � � � � 6.1 5.5 5.9 6.1 24.0 15.0 26.0 21.0 GT3 Gas turbine 3 � � � � 383.1 1.3 12.5 128.9 13.0 18.8 20.0 24.0 31.2 52.8 89.4 85.5 130.6 80.4 121.0 96.7 CTRC Coal Trinco � � � � � 3,776.2 3,776.3 3,776.3 3,776.3 3,776.3 3,776.3 3,776.3 3,776.3 3,776.3 3,776.3 3,776.3 3,776.3 3,776.3 3,776.3 3,776.3 CCHF CC�Heavy Fuel � � � � � � � � � � � � � � � � � � � � CCDL CC�Diesel � � � � � � � � � � � � � � � � � � � � CCLN CC�LNG � � � � � � � � 3,040.6 4,544.8 6,072.3 7,703.5 9,410.6 11,191.3 12,979.6 15,346.1 17,257.1 19,707.6 21,841.0 24,531.2 COSB Coal�Subcritical � � � � � 1,963.6 3,804.2 4,035.8 4,148.2 4,224.6 4,268.2 4,291.2 4,301.7 4,305.6 4,306.7 4,306.9 4,307.0 4,307.0 4,307.0 4,307.0 COSP Coal�Supercritical � � � � � � � � � � � � � � � � � � � � PUMP Pumped Storage (generation) � � � � � � � � � � � � � � � � � � � � Thermal Total 5,363.2 6,319.5 7,330.8 8,001.1 9,130.9 10,361.8 11,635.7 13,031.0 14,508.3 15,977.6 17,489.8 19,136.6 20,886.6 22,721.1 24,588.7 26,554.1 28,573.6 30,790.0 33,070.0 35,641.8 Grand Total 9,738.7 10,695.0 11,706.3 12,797.9 13,927.7 15,158.6 16,432.5 17,827.8 19,305.1 20,774.4 22,286.6 23,933.4 25,683.4 27,517.9 29,385.5 31,350.9 33,370.4 35,586.8 37,866.8 40,438.6 Forecast demand 9,739.0 10,697.0 11,707.0 12,803.0 13,935.0 15,158.0 16,431.0 17,831.0 19,306.0 20,778.0 22,291.0 23,940.0 25,691.0 27,525.0 29,393.0 31,360.0 33,380.0 35,592.0 37,878.0 40,448.0 Unserved Energy 0.3 2.0 0.7 5.2 7.3 (0.6) (1.5) 3.2 0.9 3.6 4.4 6.6 7.6 7.1 7.5 9.1 9.6 5.3 11.2 9.4 Sri Lanka: Environmental Issues in the Power Sector 172 ECA, RMA and ERM Detailed outputs from the model for the 15 cases Case 3: Energy Balance in GWh Case 3 Hydro Forced 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 Existing and Committed Hydro plants Hydro1 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 Hydro2 � � � 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 New Hydro Plants Hydro3 � � � � � 236.2 236.2 236.2 236.2 236.2 236.2 236.2 236.2 236.2 236.2 236.2 236.2 236.2 236.2 236.2 Hydro4 � � � � � � 640.9 640.9 640.9 640.9 640.9 640.9 640.9 640.9 640.9 640.9 640.9 640.9 640.9 640.9 Hydro Total 4,375.5 4,375.5 4,375.5 4,796.8 4,796.8 5,033.0 5,673.9 5,673.9 5,673.9 5,673.9 5,673.9 5,673.9 5,673.9 5,673.9 5,673.9 5,673.9 5,673.9 5,673.9 5,673.9 5,673.9 Existing and Committed Thermal plants GTSM Small Gas Turbines 1.6 5.4 � � � � � � � � � � � � � � � � � � DSP Diesel Sapugaskanda 435.4 418.7 347.1 383.7 � � � � � � � � � � � � � � � � DSPX Diesel Sapugaskanda�Extension 462.0 462.0 462.0 462.0 462.0 425.0 219.4 179.8 164.2 150.4 135.4 143.4 152.7 87.5 79.6 51.4 � � � � GT7 Gas Turbine 7 11.8 34.5 8.8 37.9 27.9 0.2 0.0 0.0 0.1 � � � � � � � � � � � DLDL Lakdhanavi Diesel 137.0 99.6 48.5 84.1 � � � � � � � � � � � � � � � � DAPL Asia Power Diesel 328.9 322.8 280.7 307.3 321.4 157.2 48.0 40.2 41.1 � � � � � � � � � � � CCKP Kelanitissa Combined Cycle 126.6 208.2 70.3 206.2 646.0 82.5 7.9 14.3 14.7 23.8 24.4 37.2 53.8 13.5 112.4 95.2 43.4 26.0 107.3 80.0 CAES AES Combined Cycle 902.6 573.6 273.4 474.3 1,049.7 270.5 106.1 69.9 85.0 96.7 93.0 141.4 162.8 40.9 231.6 � � � � � DCPL Colombo Power Diesel 417.6 388.2 299.6 347.4 402.7 180.4 � � � � � � � � � � � � � � DHOR Horana Diesel 152.8 124.9 66.2 100.1 � � � � � � � � � � � � � � � � DMAT Matara Diesel 151.2 119.3 57.4 � � � � � � � � � � � � � � � � � DPUT Puttalam Diesel 696.2 694.1 638.8 678.0 688.2 421.8 � � � � � � � � � � � � � � DEMB Embilipitiya Diesel 671.2 585.5 365.1 489.2 633.0 243.4 � � � � � � � � � � � � � � GTKW Kerawalapitiya Gas Turbine 398.4 � � � � � � � � � � � � � � � � � � � CCKW Kerawalapitiya Combined Cycle � 1,813.0 1,789.8 1,804.9 1,810.9 1,450.0 524.5 445.3 394.5 374.1 391.9 386.5 434.2 197.9 492.9 281.4 148.4 83.4 301.9 226.3 CPUT Coal Puttalam � � 2,153.5 2,153.5 2,153.5 2,153.5 2,138.1 2,094.3 2,021.4 1,926.7 1,818.3 1,732.5 1,665.2 1,352.1 1,535.3 1,288.3 999.7 781.2 1,080.4 937.9 NCRE Existing and New RENW Renewables 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 New Thermal Power Plants GT1 Gas turbine 1 � � � 3.1 � � � � � � � � � � 8.0 9.1 5.9 3.9 8.1 6.9 GT2 Gas turbine 2 � � � � � � � � � � � � � � � � � � 14.7 12.3 GT3 Gas turbine 3 � � � � 465.8 14.4 1.0 1.3 2.0 5.6 7.0 12.1 20.3 8.1 60.2 56.5 32.3 20.8 111.6 90.2 CTRC Coal Trinco � � � � � � 3,776.1 5,660.1 7,527.5 9,371.4 11,180.1 12,974.8 14,731.9 13,996.1 14,344.6 13,496.8 12,394.3 11,152.1 12,065.6 11,089.4 CCHF CC�Heavy Fuel � � � � � � � � � � � � � � � � � � � � CCDL CC�Diesel � � � � � � � � � � � � � � � � � � � � CCLN CC�LNG � � � � � � � � � � � � � � � � � � � � COSB Coal�Subcritical � � � � � 4,257.1 3,468.0 3,182.5 2,911.8 2,685.2 2,497.3 2,367.6 2,323.5 1,514.5 2,208.9 1,589.8 1,102.8 754.0 1,381.7 1,124.7 COSP Coal�Supercritical � � � � � � � � � � � � � 4,169.3 4,169.3 8,338.6 12,503.8 16,623.7 16,652.9 20,727.5 PUMP Pumped Storage (generation) � � � � � � � � � � � � � � � � � � � � Thermal Total 5,363.2 6,319.5 7,330.8 8,001.3 9,130.7 10,125.6 10,758.8 12,157.4 13,632.1 15,103.8 16,617.0 18,265.4 20,014.1 21,849.6 23,712.5 25,676.7 27,700.2 29,914.8 32,193.9 34,764.9 Grand Total 9,738.7 10,695.0 11,706.3 12,798.1 13,927.5 15,158.6 16,432.7 17,831.3 19,306.0 20,777.7 22,290.9 23,939.3 25,688.0 27,523.5 29,386.4 31,350.6 33,374.1 35,588.7 37,867.8 40,438.8 Forecast demand 9,739.0 10,697.0 11,707.0 12,803.0 13,935.0 15,158.0 16,431.0 17,831.0 19,306.0 20,778.0 22,291.0 23,940.0 25,691.0 27,525.0 29,393.0 31,360.0 33,380.0 35,592.0 37,878.0 40,448.0 Unserved Energy 0.3 2.0 0.7 4.9 7.5 (0.6) (1.7) (0.3) 0.1 0.3 0.1 0.7 3.0 1.5 6.6 9.4 5.9 3.3 10.2 9.2 Sri Lanka: Environmental Issues in the Power Sector 173 ECA, RMA and ERM Detailed outputs from the model for the 15 cases Case 4: Energy Balance in GWh Case 4 NCRE Target 10% by 2015 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 Existing and Committed Hydro plants Hydro1 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 Hydro2 � � � 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 New Hydro Plants Hydro3 Hydro4 Hydro Total 4,375.5 4,375.5 4,375.5 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 Existing and Committed Thermal plants GTSM Small Gas Turbines 1.5 4.1 � � � � � � � � � � � � � � � � � � DSP Diesel Sapugaskanda 435.4 414.6 323.2 360.8 � � � � � � � � � � � � � � � � DSPX Diesel Sapugaskanda�Extension 462.0 462.0 461.9 462.0 462.0 396.9 196.8 158.1 131.0 119.6 119.0 112.4 112.6 56.2 55.8 33.0 � � � � GT7 Gas Turbine 7 10.9 24.4 4.7 15.4 100.0 0.9 0.8 0.9 1.2 � � � � � � � � � � � DLDL Lakdhanavi Diesel 136.5 91.2 41.2 61.4 � � � � � � � � � � � � � � � � DAPL Asia Power Diesel 328.9 319.6 266.7 287.0 311.4 131.4 44.9 32.1 28.8 � � � � � � � � � � � CCKP Kelanitissa Combined Cycle 121.1 177.7 47.9 135.2 469.3 30.7 11.2 13.2 13.1 20.1 20.6 29.5 38.7 12.4 65.8 54.9 29.1 42.4 60.8 45.2 CAES AES Combined Cycle 889.0 515.6 224.1 381.1 884.5 154.5 82.5 54.3 61.3 81.5 83.5 91.0 104.8 32.2 145.8 � � � � � DCPL Colombo Power Diesel 417.1 379.5 258.3 306.5 383.9 141.5 � � � � � � � � � � � � � � DHOR Horana Diesel 152.2 118.8 53.9 76.3 � � � � � � � � � � � � � � � � DMAT Matara Diesel 150.2 108.0 47.7 � � � � � � � � � � � � � � � � � DPUT Puttalam Diesel 696.2 690.7 618.1 654.9 676.8 339.8 � � � � � � � � � � � � � � DEMB Embilipitiya Diesel 668.8 551.5 300.1 411.9 589.3 179.9 � � � � � � � � � � � � � � GTKW Kerawalapitiya Gas Turbine 387.7 � � � � � � � � � � � � � � � � � � � CCKW Kerawalapitiya Combined Cycle � 1,812.6 1,771.2 1,793.4 1,803.5 1,261.6 432.4 348.2 324.5 310.2 307.3 296.4 325.9 121.9 343.1 177.2 92.6 122.1 170.2 120.7 CPUT Coal Puttalam � � 2,153.4 2,153.5 2,153.5 2,153.5 2,126.7 2,049.6 1,940.3 1,810.3 1,669.7 1,581.4 1,494.6 1,068.8 1,338.4 1,010.3 707.1 997.1 1,237.0 1,061.0 NCRE Existing and New RENW Renewables 505.0 650.4 758.8 903.4 1,120.2 1,373.1 1,626.1 1,806.8 1,951.3 2,059.7 2,204.2 2,312.6 2,493.3 2,710.1 2,926.9 3,107.6 3,324.4 3,469.0 3,649.6 3,866.4 New Thermal Power Plants GT1 Gas turbine 1 � � � � 33.8 0.3 0.3 0.4 0.6 2.6 3.5 5.3 8.1 3.0 14.2 14.3 8.1 13.3 14.9 11.3 GT2 Gas turbine 2 � � � � � � � � � � � � � � � � � � � � GT3 Gas turbine 3 � � � � 145.0 4.1 1.9 2.0 2.6 4.5 5.5 8.0 11.4 4.0 36.2 32.8 17.8 28.8 57.0 43.1 CTRC Coal Trinco � � � � � � 3,775.7 5,652.3 7,497.1 9,300.6 11,047.3 12,785.0 14,460.9 13,425.3 13,841.8 12,667.2 11,189.3 12,085.6 12,743.6 11,713.9 CCHF CC�Heavy Fuel � � � � � � � � � � � � � � � � � � � � CCDL CC�Diesel � � � � � � � � � � � � � � � � � � � � CCLN CC�LNG � � � � � � � � � � � � � � � � � � � � COSB Coal�Subcritical � � � � � 4,193.6 3,336.4 2,916.3 2,557.1 2,270.8 2,032.4 1,918.9 1,838.2 1,122.8 1,652.3 1,119.5 731.5 1,534.3 2,635.6 2,158.4 COSP Coal�Supercritical � � � � � � � � � � � � � 4,169.3 4,169.2 8,338.4 12,479.0 12,494.6 12,502.1 16,623.1 PUMP Pumped Storage (generation) � � � � � � � � � � � � � � � � � � � � Thermal Total 5,362.3 6,320.6 7,331.1 8,002.7 9,132.9 10,361.6 11,635.7 13,034.3 14,508.8 15,979.9 17,492.8 19,140.5 20,888.5 22,725.8 24,589.6 26,555.1 28,578.9 30,787.2 33,070.9 35,643.0 Grand Total 9,737.8 10,696.1 11,706.6 12,799.5 13,929.7 15,158.4 16,432.5 17,831.1 19,305.6 20,776.7 22,289.6 23,937.3 25,685.3 27,522.6 29,386.4 31,351.9 33,375.7 35,584.0 37,867.7 40,439.8 Forecast demand 9,739.0 10,697.0 11,707.0 12,803.0 13,935.0 15,158.0 16,431.0 17,831.0 19,306.0 20,778.0 22,291.0 23,940.0 25,691.0 27,525.0 29,393.0 31,360.0 33,380.0 35,592.0 37,878.0 40,448.0 Unserved Energy 1.2 0.9 0.4 3.5 5.3 (0.4) (1.5) (0.1) 0.4 1.3 1.4 2.7 5.7 2.4 6.6 8.1 4.3 8.0 10.3 8.2 Sri Lanka: Environmental Issues in the Power Sector 174 ECA, RMA and ERM Detailed outputs from the model for the 15 cases Case 5: Energy Balance in GWh Case 5 LNG, Hydro and NCRE forced 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 Existing and Committed Hydro plants Hydro1 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 Hydro2 � � � 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 New Hydro Plants Hydro3 � � � � � 236.2 236.2 236.2 236.2 236.2 236.2 236.2 236.2 236.2 236.2 236.2 236.2 236.2 236.2 236.2 Hydro4 � � � � � � 640.9 640.9 640.9 640.9 640.9 640.9 640.9 640.9 640.9 640.9 640.9 640.9 640.9 640.9 Hydro Total 4,375.5 4,375.5 4,375.5 4,796.8 4,796.8 5,033.0 5,673.9 5,673.9 5,673.9 5,673.9 5,673.9 5,673.9 5,673.9 5,673.9 5,673.9 5,673.9 5,673.9 5,673.9 5,673.9 5,673.9 Existing and Committed Thermal plants GTSM Small Gas Turbines 1.5 4.1 � � � � � � � � � � � � � � � � � � DSP Diesel Sapugaskanda 435.4 414.6 323.2 360.8 � � � � � � � � � � � � � � � � DSPX Diesel Sapugaskanda�Extension 462.0 462.0 461.9 462.0 462.0 281.4 144.2 226.4 176.1 141.1 111.8 101.9 96.6 90.8 47.1 22.9 � � � � GT7 Gas Turbine 7 10.9 24.4 4.7 15.4 100.0 0.1 0.0 0.6 0.9 � � � � � � � � � � � DLDL Lakdhanavi Diesel 136.5 91.2 41.2 61.4 � � � � � � � � � � � � � � � � DAPL Asia Power Diesel 328.9 319.6 266.7 287.0 311.4 40.6 15.8 63.2 43.4 � � � � � � � � � � � CCKP Kelanitissa Combined Cycle 121.1 177.7 47.9 135.2 469.3 0.9 0.8 24.6 13.5 18.2 16.5 17.2 18.7 22.4 30.6 25.7 37.4 54.9 75.7 120.4 CAES AES Combined Cycle 889.0 515.6 224.1 381.1 884.5 12.7 15.3 124.7 83.0 74.7 49.6 57.1 54.0 56.6 73.3 � � � � � DCPL Colombo Power Diesel 417.1 379.5 258.3 306.5 383.9 38.9 � � � � � � � � � � � � � � DHOR Horana Diesel 152.2 118.8 53.9 76.3 � � � � � � � � � � � � � � � � DMAT Matara Diesel 150.2 108.0 47.7 � � � � � � � � � � � � � � � � � DPUT Puttalam Diesel 696.2 690.7 618.1 654.9 676.8 126.8 � � � � � � � � � � � � � � DEMB Embilipitiya Diesel 668.8 551.5 300.1 411.9 589.3 32.0 � � � � � � � � � � � � � � GTKW Kerawalapitiya Gas Turbine 387.7 � � � � � � � � � � � � � � � � � � � CCKW Kerawalapitiya Combined Cycle � 1,812.6 1,771.2 1,793.4 1,803.5 629.4 248.5 604.5 455.3 339.2 292.6 245.0 232.6 215.8 262.1 99.3 133.4 177.1 225.4 298.0 CPUT Coal Puttalam � � 2,153.4 2,153.5 2,153.5 2,090.8 2,088.7 2,120.6 2,137.6 2,146.7 2,150.6 2,152.8 2,153.3 2,153.4 2,153.4 2,153.4 2,153.4 2,153.4 2,153.5 2,153.5 NCRE Existing and New RENW Renewables 505.9 650.4 758.8 903.4 1,120.2 1,373.1 1,626.1 1,806.8 1,951.3 2,059.7 2,204.2 2,312.6 2,493.3 2,710.1 2,926.9 3,107.6 3,324.4 3,469.0 3,649.6 3,866.4 New Thermal Power Plants GT1 Gas turbine 1 � � � � 33.8 0.0 0.0 0.3 0.4 1.8 2.1 2.9 4.0 5.6 8.7 8.1 8.8 7.4 8.6 8.2 GT2 Gas turbine 2 � � � � � � � � � � � � � � � � � 5.9 6.6 6.3 GT3 Gas turbine 3 � � � � 145.0 0.1 0.1 2.1 1.8 3.0 3.3 4.3 5.5 7.4 10.5 9.7 24.9 49.8 85.1 160.7 CTRC Coal Trinco � � � � � 3,773.8 3,772.5 3,774.9 3,775.9 3,776.1 3,776.2 3,776.2 3,776.3 3,776.3 3,776.3 3,776.3 3,776.3 3,776.3 3,776.3 3,776.3 CCHF CC�Heavy Fuel � � � � � � � � � � � � � � � � � � � � CCDL CC�Diesel � � � � � � � � � � � � � � � � � � � � CCLN CC�LNG � � � � � � � � 1,278.9 2,606.6 3,932.9 5,418.3 6,944.7 8,539.5 10,136.7 12,179.2 13,936.6 15,911.7 17,906.5 20,067.2 COSB Coal�Subcritical � � � � � 1,725.2 2,846.8 3,408.7 3,713.9 3,936.1 4,076.4 4,176.2 4,235.0 4,268.7 4,286.0 4,295.8 4,301.6 4,305.2 4,306.4 4,306.8 COSP Coal�Supercritical � � � � � � � � � � � � � � � � � � � � PUMP Pumped Storage (generation) � � � � � � � � � � � � � � � � � � � � Thermal Total 5,363.2 6,320.6 7,331.1 8,002.7 9,132.9 10,125.6 10,758.8 12,157.3 13,631.9 15,103.1 16,616.1 18,264.5 20,013.9 21,846.4 23,711.5 25,678.0 27,696.8 29,910.6 32,193.7 34,763.8 Grand Total 9,738.7 10,696.1 11,706.6 12,799.5 13,929.7 15,158.6 16,432.7 17,831.2 19,305.8 20,777.0 22,290.0 23,938.4 25,687.8 27,520.3 29,385.4 31,351.9 33,370.7 35,584.5 37,867.6 40,437.7 Forecast demand 9,739.0 10,697.0 11,707.0 12,803.0 13,935.0 15,158.0 16,431.0 17,831.0 19,306.0 20,778.0 22,291.0 23,940.0 25,691.0 27,525.0 29,393.0 31,360.0 33,380.0 35,592.0 37,878.0 40,448.0 Unserved Energy 0.3 0.9 0.4 3.5 5.3 (0.6) (1.7) (0.2) 0.3 1.1 1.0 1.6 3.3 4.7 7.6 8.1 9.3 7.5 10.4 10.3 Sri Lanka: Environmental Issues in the Power Sector 175 ECA, RMA and ERM Detailed outputs from the model for the 15 cases Case 6: Energy Balance in GWh Case 6 Early Supercritical Coal 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 Existing and Committed Hydro plants Hydro1 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 Hydro2 � � � 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 New Hydro Plants Hydro3 Hydro4 Hydro Total 4,375.5 4,375.5 4,375.5 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 Existing and Committed Thermal plants GTSM Small Gas Turbines 1.6 5.4 � � � � � � � � � � � � � � � � � � DSP Diesel Sapugaskanda 435.4 418.7 347.1 384.3 � � � � � � � � � � � � � � � � DSPX Diesel Sapugaskanda�Extension 462.0 462.0 462.0 462.0 462.0 434.2 299.7 373.0 207.1 73.7 144.3 76.3 25.7 85.4 22.0 50.4 � � � � GT7 Gas Turbine 7 11.8 34.5 8.8 36.8 123.5 2.0 2.1 26.7 3.9 � � � � � � � � � � � DLDL Lakdhanavi Diesel 137.0 99.6 48.5 84.0 � � � � � � � � � � � � � � � � DAPL Asia Power Diesel 328.9 322.8 280.7 306.4 321.7 179.1 85.5 161.0 63.8 � � � � � � � � � � � CCKP Kelanitissa Combined Cycle 126.6 208.2 70.3 196.6 646.0 98.3 61.2 251.5 44.2 9.6 53.8 14.0 6.6 26.3 14.6 39.5 24.9 16.8 33.0 27.6 CAES AES Combined Cycle 902.6 573.6 273.4 481.1 1,054.2 325.1 220.9 472.4 141.0 29.3 150.2 39.6 14.2 67.5 29.9 � � � � � DCPL Colombo Power Diesel 417.6 388.2 299.6 348.0 403.7 199.6 � � � � � � � � � � � � � � DHOR Horana Diesel 152.8 124.9 66.2 102.1 � � � � � � � � � � � � � � � � DMAT Matara Diesel 151.2 119.3 57.4 � � � � � � � � � � � � � � � � � DPUT Puttalam Diesel 696.2 694.1 638.8 676.8 688.8 442.9 � � � � � � � � � � � � � � DEMB Embilipitiya Diesel 671.2 585.5 365.1 492.0 639.9 270.0 � � � � � � � � � � � � � � GTKW Kerawalapitiya Gas Turbine 398.4 � � � � � � � � � � � � � � � � � � � CCKW Kerawalapitiya Combined Cycle � 1,813.0 1,789.8 1,804.7 1,810.9 1,500.1 753.9 1,185.1 501.5 150.2 401.2 156.1 49.1 217.7 101.2 299.6 196.1 114.1 197.4 153.8 CPUT Coal Puttalam � � 2,153.5 2,153.5 2,153.5 2,153.5 2,149.6 2,152.7 2,036.2 1,631.3 1,807.9 1,389.0 949.3 1,269.4 885.9 1,232.6 920.9 701.1 968.6 843.3 NCRE Existing and New RENW Renewables 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 New Thermal Power Plants GT1 Gas turbine 1 � � � 3.1 50.8 0.8 1.0 13.3 2.7 2.1 9.3 3.6 1.4 8.2 4.5 15.8 10.5 6.9 15.1 12.8 GT2 Gas turbine 2 � � � � 307.3 17.9 11.5 113.9 12.5 4.1 17.5 6.8 2.6 12.6 7.6 20.4 13.4 9.3 18.6 15.6 GT3 Gas turbine 3 � � � � � � � � � � � � � � � � � � � � CTRC Coal Trinco � � � � � � 3,776.3 3,776.3 3,760.0 3,460.9 3,588.6 3,098.3 2,490.1 2,849.2 2,378.9 2,675.2 2,259.2 1,834.0 2,293.5 1,964.7 CCHF CC�Heavy Fuel � � � � � � � � � � � � � � � � � � 305.3 258.6 CCDL CC�Diesel � � � � � � � � � � � � � � � 173.8 95.9 60.6 115.6 89.4 CCLN CC�LNG � � � � � � � � � � � � � � � � � � � � COSB Coal�Subcritical � � � � � 4,268.4 3,804.2 4,035.8 3,096.0 1,823.9 2,511.6 1,538.8 846.7 1,449.6 888.0 1,457.8 1,051.4 770.1 1,270.1 1,089.0 COSP Coal�Supercritical � � � � � � � � 4,169.3 8,325.3 8,334.3 12,349.1 16,037.6 16,266.3 19,791.5 20,117.3 23,534.4 26,808.7 27,381.8 30,715.6 PUMP Pumped Storage (generation) � � � � � � � � � � � � � � � � � � � � Thermal Total 5,363.2 6,319.5 7,330.8 8,001.1 9,132.0 10,361.7 11,635.7 13,031.5 14,507.8 15,980.1 17,488.3 19,141.4 20,893.0 22,722.0 24,593.8 26,552.1 28,576.4 30,791.3 33,068.6 35,640.1 Grand Total 9,738.7 10,695.0 11,706.3 12,797.9 13,928.8 15,158.5 16,432.5 17,828.3 19,304.6 20,776.9 22,285.1 23,938.2 25,689.8 27,518.8 29,390.6 31,348.9 33,373.2 35,588.1 37,865.4 40,436.9 Forecast demand 9,739.0 10,697.0 11,707.0 12,803.0 13,935.0 15,158.0 16,431.0 17,831.0 19,306.0 20,778.0 22,291.0 23,940.0 25,691.0 27,525.0 29,393.0 31,360.0 33,380.0 35,592.0 37,878.0 40,448.0 Unserved Energy 0.3 2.0 0.7 5.2 6.3 (0.5) (1.5) 2.8 1.4 1.1 5.9 1.9 1.2 6.2 2.5 11.1 6.8 3.9 12.6 11.1 Sri Lanka: Environmental Issues in the Power Sector 176 ECA, RMA and ERM Detailed outputs from the model for the 15 cases Case 7: Energy Balance in GWh Case 7 No coal beyond Trinco Commitme 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 Existing and Committed Hydro plants Hydro1 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 Hydro2 � � � 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 New Hydro Plants Hydro3 Hydro4 Hydro Total 4,375.5 4,375.5 4,375.5 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 Existing and Committed Thermal plants GTSM Small Gas Turbines 1.6 5.4 � � � � � � � � � � � � � � � � � � DSP Diesel Sapugaskanda 435.4 418.7 347.1 384.3 � � � � � � � � � � � � � � � � DSPX Diesel Sapugaskanda�Extension 462.0 462.0 462.0 462.0 462.0 317.3 120.5 232.8 187.3 152.1 138.2 129.1 126.0 126.6 63.9 44.0 � � � � GT7 Gas Turbine 7 11.8 34.5 8.8 36.8 263.6 0.9 1.0 11.6 8.9 � � � � � � � � � � � DLDL Lakdhanavi Diesel 137.0 99.6 48.5 84.0 � � � � � � � � � � � � � � � � DAPL Asia Power Diesel 328.9 322.8 280.7 306.4 321.7 68.4 17.1 63.2 55.9 � � � � � � � � � � � CCKP Kelanitissa Combined Cycle 126.6 208.2 70.3 196.6 644.4 5.5 5.6 49.6 37.8 54.8 50.4 52.7 64.5 75.3 107.6 92.9 138.7 71.8 105.6 91.5 CAES AES Combined Cycle 902.6 573.6 273.4 481.1 1,052.9 48.5 23.6 153.5 123.1 150.3 138.0 138.7 152.4 172.6 201.0 � � � � � DCPL Colombo Power Diesel 417.6 388.2 299.6 348.0 403.7 61.6 � � � � � � � � � � � � � � DHOR Horana Diesel 152.8 124.9 66.2 102.1 � � � � � � � � � � � � � � � � DMAT Matara Diesel 151.2 119.3 57.4 � � � � � � � � � � � � � � � � � DPUT Puttalam Diesel 696.2 694.1 638.8 676.8 688.9 193.0 � � � � � � � � � � � � � � DEMB Embilipitiya Diesel 671.2 585.5 365.1 492.0 640.0 69.4 � � � � � � � � � � � � � � GTKW Kerawalapitiya Gas Turbine 398.4 � � � � � � � � � � � � � � � � � � � CCKW Kerawalapitiya Combined Cycle � 1,813.0 1,789.8 1,804.7 1,810.9 868.9 225.6 585.5 500.4 429.1 390.9 392.2 388.9 386.6 429.2 267.3 310.8 204.9 261.2 228.6 CPUT Coal Puttalam � � 2,153.5 2,153.5 2,153.5 2,153.5 2,149.1 2,152.6 2,153.2 2,153.4 2,153.5 2,153.5 2,153.5 2,153.5 2,153.5 2,153.5 2,153.5 2,153.5 2,153.5 2,153.5 NCRE Existing and New RENW Renewables 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 New Thermal Power Plants GT1 Gas turbine 1 � � � 3.1 220.0 0.4 0.5 5.5 7.0 22.5 24.5 30.0 25.5 23.1 24.6 25.3 29.4 18.3 25.2 24.8 GT2 Gas turbine 2 � � � � � � � � � � � � � � � � � � 10.7 10.4 GT3 Gas turbine 3 � � � � � � � � � � � � 18.7 41.7 77.9 73.4 130.6 80.5 121.0 113.6 CTRC Coal Trinco � � � � � � 3,776.3 3,776.3 3,776.3 3,776.3 3,776.3 3,776.3 3,776.3 3,776.3 3,776.3 3,776.3 3,776.3 3,776.3 3,776.3 3,776.3 CCHF CC�Heavy Fuel � � � � � � � � � � � � � � � � � � � 325.4 CCDL CC�Diesel � � � � � � � � � � � � � � � � � � � � CCLN CC�LNG � � � � � 1,840.1 1,116.8 1,528.5 3,040.6 4,544.8 6,079.5 7,703.5 9,410.6 11,191.3 12,979.6 15,346.1 17,257.1 19,707.6 21,841.0 24,139.7 COSB Coal�Subcritical � � � � � 4,264.5 3,729.8 4,005.2 4,148.2 4,224.6 4,269.0 4,291.2 4,301.7 4,305.6 4,306.7 4,306.9 4,307.0 4,307.0 4,307.0 4,307.0 COSP Coal�Supercritical � � � � � � � � � � � � � � � � � � � � PUMP Pumped Storage (generation) � � � � � � � � � � � � � � � � � � � � Thermal Total 5,363.2 6,319.5 7,330.8 8,001.1 9,131.4 10,361.8 11,635.8 13,034.1 14,508.4 15,977.7 17,490.0 19,136.8 20,887.9 22,722.2 24,590.0 26,555.5 28,573.0 30,789.6 33,071.3 35,640.4 Grand Total 9,738.7 10,695.0 11,706.3 12,797.9 13,928.2 15,158.6 16,432.6 17,830.9 19,305.2 20,774.5 22,286.8 23,933.6 25,684.7 27,519.0 29,386.8 31,352.3 33,369.8 35,586.4 37,868.1 40,437.2 Forecast demand 9,739.0 10,697.0 11,707.0 12,803.0 13,935.0 15,158.0 16,431.0 17,831.0 19,306.0 20,778.0 22,291.0 23,940.0 25,691.0 27,525.0 29,393.0 31,360.0 33,380.0 35,592.0 37,878.0 40,448.0 Unserved Energy 0.3 2.0 0.7 5.2 6.8 (0.6) (1.6) 0.1 0.8 3.5 4.2 6.4 6.3 6.0 6.2 7.7 10.2 5.6 9.9 10.8 Sri Lanka: Environmental Issues in the Power Sector 177 ECA, RMA and ERM Detailed outputs from the model for the 15 cases Case 8: Energy Balance in GWh Case 8 Pumped storage plants allowed 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 Existing and Committed Hydro plants Hydro1 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 Hydro2 � � � 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 New Hydro Plants Hydro3 Hydro4 Hydro Total 4,375.5 4,375.5 4,375.5 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 Existing and Committed Thermal plants GTSM Small Gas Turbines 1.6 4.9 � � � � � � � � � � � � � � � � � � DSP Diesel Sapugaskanda 435.4 418.7 347.5 384.3 � � � � � � � � � � � � � � � � DSPX Diesel Sapugaskanda�Extension 462.0 462.0 462.0 462.0 462.0 434.3 299.9 107.7 107.3 102.0 108.5 109.8 45.8 109.1 31.5 15.8 � � � � GT7 Gas Turbine 7 10.6 29.1 7.4 36.3 81.9 1.1 1.3 0.2 0.4 � � � � � � � � � � � DLDL Lakdhanavi Diesel 137.0 100.9 52.8 83.8 � � � � � � � � � � � � � � � � DAPL Asia Power Diesel 328.9 322.8 280.5 306.3 321.7 182.6 79.6 15.3 21.0 � � � � � � � � � � � CCKP Kelanitissa Combined Cycle 123.5 210.5 65.5 196.1 646.3 95.0 61.7 7.1 8.1 13.6 20.1 28.1 9.2 48.8 23.8 24.4 42.6 24.9 51.0 35.2 CAES AES Combined Cycle 902.6 575.2 267.3 481.4 1,049.7 321.2 217.2 33.1 38.1 57.9 60.3 82.2 25.2 106.8 52.2 � � � � � DCPL Colombo Power Diesel 417.6 388.4 302.1 348.0 403.2 193.5 � � � � � � � � � � � � � � DHOR Horana Diesel 152.8 124.6 66.2 102.2 � � � � � � � � � � � � � � � � DMAT Matara Diesel 151.2 120.2 59.8 � � � � � � � � � � � � � � � � � DPUT Puttalam Diesel 696.2 694.1 639.2 676.9 688.7 452.5 � � � � � � � � � � � � � � DEMB Embilipitiya Diesel 671.2 585.7 367.6 492.8 643.9 269.8 � � � � � � � � � � � � � � GTKW Kerawalapitiya Gas Turbine 402.6 � � � � � � � � � � � � � � � � � � � CCKW Kerawalapitiya Combined Cycle � 1,813.0 1,789.8 1,804.7 1,810.9 1,499.1 760.2 263.7 272.5 281.9 257.2 265.7 86.2 295.1 142.4 79.1 138.3 134.2 186.0 189.6 CPUT Coal Puttalam � � 2,153.5 2,153.5 2,153.5 2,153.5 2,149.6 1,997.7 1,880.0 1,761.8 1,663.0 1,574.9 1,182.1 1,446.5 1,126.0 803.5 1,128.6 875.2 1,176.0 1,030.1 NCRE Existing and New RENW Renewables 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 New Thermal Power Plants GT1 Gas turbine 1 � � � 3.1 19.9 0.3 0.5 0.1 0.1 0.7 1.1 2.2 0.9 6.3 3.5 4.1 8.3 5.6 11.8 9.7 GT2 Gas turbine 2 � � � � � � � � � � � � � � � � � � � � GT3 Gas turbine 3 � � � � 379.7 20.7 12.5 1.6 2.5 5.1 7.3 11.6 4.5 26.9 13.5 14.9 24.8 15.8 28.0 22.3 CTRC Coal Trinco � � � � � � 3,776.3 7,525.6 9,358.8 11,157.0 12,928.6 14,660.1 13,777.3 14,194.8 13,222.4 11,943.8 13,050.6 11,715.3 13,140.9 11,960.8 CCHF CC�Heavy Fuel � � � � � � � � � � � � � � � � � � � � CCDL CC�Diesel � � � � � � � � � � � � � � � � � � � � CCLN CC�LNG � � � � � � � � � � � � � � � � � � � � COSB Coal�Subcritical � � � � � 4,268.4 3,807.3 2,612.6 2,350.6 2,131.0 1,978.0 1,937.5 1,122.8 1,846.4 1,168.8 699.6 1,303.0 929.9 1,562.2 1,259.0 COSP Coal�Supercritical � � � � � � � � � � � � 4,169.3 4,169.3 8,338.6 12,502.5 12,507.9 16,670.9 16,677.2 20,841.0 PUMP Pumped Storage (generation) � � � � � � � � � � � � � � � � 233.7 120.9 541.9 410.4 Thermal Total 5,363.2 6,319.8 7,330.9 8,001.0 9,130.9 10,361.7 11,635.7 13,034.4 14,509.1 15,980.7 17,493.8 19,141.9 20,893.1 22,719.7 24,592.3 26,557.4 28,907.6 30,962.3 33,844.7 36,227.8 Grand Total 9,738.7 10,695.3 11,706.4 12,797.8 13,927.7 15,158.5 16,432.5 17,831.2 19,305.9 20,777.5 22,290.6 23,938.7 25,689.9 27,516.5 29,389.1 31,354.2 33,704.4 35,759.1 38,641.5 41,024.6 Forecast demand 9,739.0 10,697.0 11,707.0 12,803.0 13,935.0 15,158.0 16,431.0 17,831.0 19,306.0 20,778.0 22,291.0 23,940.0 25,691.0 27,525.0 29,393.0 31,360.0 33,380.0 35,592.0 37,878.0 40,448.0 Unserved Energy 0.3 1.7 0.6 5.2 7.3 (0.5) (1.5) (0.2) 0.1 0.5 0.4 1.3 1.2 8.5 3.9 5.8 (324.4) (167.1) (763.5) (576.6) Sri Lanka: Environmental Issues in the Power Sector 178 ECA, RMA and ERM Detailed outputs from the model for the 15 cases Case 9: Energy Balance in GWh Case 9 DSM intervention 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 Existing and Committed Hydro plants Hydro1 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 Hydro2 � � � 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 New Hydro Plants Hydro3 Hydro4 Hydro Total 4,375.5 4,375.5 4,375.5 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 Existing and Committed Thermal plants GTSM Small Gas Turbines 1.8 4.4 � � � � � � � 0 0 � � � � � � � � � DSP Diesel Sapugaskanda 435.4 414.9 329.2 365.4 � � � � � 0 0 � � � � � � � � � DSPX Diesel Sapugaskanda�Extension 462.0 462.0 461.7 461.9 461.9 416.5 262.6 83.9 81.5 80.46 83.32 91.2 168.7 108.1 25.7 60.9 � � � � GT7 Gas Turbine 7 12.6 28.8 4.7 17.7 43.5 0.1 0.1 0.0 0.0 0 0 � � � � � � � � � DLDL Lakdhanavi Diesel 137.3 96.3 42.1 67.5 � � � � � 0 0 � � � � � � � � � DAPL Asia Power Diesel 328.9 321.0 268.4 291.2 314.0 153.7 56.2 6.6 6.9 0 0 � � � � � � � � � CCKP Kelanitissa Combined Cycle 131.6 192.4 50.5 156.0 519.8 38.1 16.4 0.7 1.1 2.29 4.91 7.1 83.1 18.5 8.2 142.8 67.8 30.8 20.5 116.9 CAES AES Combined Cycle 912.5 547.6 224.7 393.2 945.7 209.1 142.6 9.4 11.3 16.57 21.59 36.8 220.2 65.7 23.2 � � � � � DCPL Colombo Power Diesel 418.0 382.5 282.1 321.3 389.3 173.3 � � � 0 0 � � � � � � � � � DHOR Horana Diesel 153.5 121.4 57.4 84.3 � � � � � 0 0 � � � � � � � � � DMAT Matara Diesel 151.6 115.9 50.7 � � � � � � 0 0 � � � � � � � � � DPUT Puttalam Diesel 696.2 692.5 616.9 660.5 678.8 395.8 � � � 0 0 � � � � � � � � � DEMB Embilipitiya Diesel 672.3 572.1 333.2 442.7 610.8 224.7 � � � 0 0 � � � � � � � � � GTKW Kerawalapitiya Gas Turbine 407.1 � � � � � � � � 0 0 � � � � � � � � � CCKW Kerawalapitiya Combined Cycle � 1,812.6 1,764.7 1,791.4 1,804.7 1,399.7 611.6 151.3 180.3 196.77 190.99 207.3 503.3 263.9 97.3 352.4 229.3 120.1 66.6 293.8 CPUT Coal Puttalam � � 2,153.4 2,153.4 2,153.5 2,153.5 2,141.1 1,923.2 1,793.9 1670.45 1584.87 1,498.5 1,678.7 1,380.9 1,026.2 1,307.3 1,036.8 820.3 633.3 935.4 NCRE Existing and New RENW Renewables 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 New Thermal Power Plants GT1 Gas turbine 1 � � � � � � � � � 0 0 � 1.5 0.7 0.4 4.0 2.5 1.5 1.0 3.5 GT2 Gas turbine 2 � � � � � � � � � 0 0 � � � � � � � � � GT3 Gas turbine 3 � � � � 254.9 5.8 1.3 0.2 0.3 0.62 1.09 2.0 29.5 8.0 4.2 90.5 46.8 27.8 19.2 125.9 CTRC Coal Trinco � � � � � � 3,776.2 7,497.9 9,306.7 11072.31 12819.71 14,523.2 14,748.3 14,022.9 12,954.9 13,531.0 12,458.4 11,208.1 10,058.0 11,149.9 CCHF CC�Heavy Fuel � � � � � � � � � 0 0 � � � � � � � � � CCDL CC�Diesel � � � � � � � � � 0 0 � � � � � � � � � CCLN CC�LNG � � � � � � � � � 0 0 � � � � � � � � � COSB Coal�Subcritical � � � � � 4,230.2 3,634.8 2,335.5 2,118.4 1917.3 1804.58 1,752.5 2,414.6 1,698.6 1,084.9 1,694.4 1,247.7 907.7 646.4 1,197.3 COSP Coal�Supercritical � � � � � � � � � 0 0 � � 4,169.3 8,338.6 8,338.6 12,503.8 16,623.7 20,624.7 20,727.3 PUMP Pumped Storage (generation) � � � � � � � � � � � � � � � � � � � � Thermal Total 5,390.5 6,234.1 7,109.4 7,676.3 8,646.7 9,870.0 11,112.6 12,478.4 13,970.2 15,426.5 16,980.8 18,588.2 20,317.8 22,206.3 24,033.1 25,991.5 28,063.0 30,209.9 32,539.5 35,019.7 Grand Total 9,766.0 10,609.6 11,484.9 12,473.1 13,443.5 14,666.8 15,909.4 17,275.2 18,767.0 20,223.3 21,777.6 23,385.0 25,114.6 27,003.1 28,829.9 30,788.3 32,859.8 35,006.7 37,336.3 39,816.5 Forecast demand 9,764.0 10,607.7 11,491.2 12,469.6 13,446.7 14,670.2 15,919.4 17,286.8 18,776.4 20,234.0 21,765.3 23,390.2 25,130.2 26,991.6 28,841.3 30,787.1 32,847.0 35,034.8 37,362.6 39,841.7 Unserved Energy (2.0) (1.9) 6.3 (3.5) 3.3 3.4 10.0 11.6 9.4 10.7 (12.4) 5.2 15.6 (11.6) 11.3 (1.2) (12.8) 28.2 26.3 25.2 Sri Lanka: Environmental Issues in the Power Sector 179 ECA, RMA and ERM Detailed outputs from the model for the 15 cases Case 10: Energy Balance in GWh Case 10 High demand forecast 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 Existing and Committed Hydro plants Hydro1 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 Hydro2 � � � 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 New Hydro Plants Hydro3 Hydro4 Hydro Total 4,375.5 4,375.5 4,375.5 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 Existing and Committed Thermal plants GTSM Small Gas Turbines 1.6 10.2 � � � � � � � � � � � � � � � � � � DSP Diesel Sapugaskanda 435.4 422.5 379.5 162.5 � � � � � � � � � � � � � � � � DSPX Diesel Sapugaskanda�Extension 462.0 462.0 462.0 462.0 462.0 305.7 188.0 183.6 168.0 101.6 176.8 249.8 172.4 125.1 45.6 31.6 � � � � GT7 Gas Turbine 7 11.8 57.2 9.8 0.4 12.8 0.0 0.0 0.1 0.2 � � � � � � � � � � � DLDL Lakdhanavi Diesel 137.0 112.5 76.1 23.5 � � � � � � � � � � � � � � � � DAPL Asia Power Diesel 328.9 326.7 305.4 157.8 258.1 4.3 2.0 3.1 5.4 � � � � � � � � � � � CCKP Kelanitissa Combined Cycle 126.6 268.7 165.2 9.6 266.5 0.5 1.0 1.7 3.3 1.5 12.4 73.6 33.7 18.0 12.3 16.2 12.7 54.8 46.7 47.2 CAES AES Combined Cycle 902.6 673.4 425.3 106.8 535.0 2.4 3.8 6.2 11.0 5.3 33.6 163.0 76.2 38.8 26.0 � � � � � DCPL Colombo Power Diesel 417.6 397.2 337.7 135.5 300.4 3.4 � � � � � � � � � � � � � � DHOR Horana Diesel 152.8 135.4 97.7 27.1 � � � � � � � � � � � � � � � � DMAT Matara Diesel 151.2 126.9 87.6 � � � � � � � � � � � � � � � � � DPUT Puttalam Diesel 696.2 694.8 672.4 433.6 592.1 20.3 � � � � � � � � � � � � � � DEMB Embilipitiya Diesel 671.2 611.4 485.7 154.3 433.2 3.4 � � � � � � � � � � � � � � GTKW Kerawalapitiya Gas Turbine 398.4 � � � � � � � � � � � � � � � � � � � CCKW Kerawalapitiya Combined Cycle � 1,813.1 1,801.8 1,520.1 1,700.4 223.0 43.5 52.0 81.9 24.1 135.6 375.7 209.2 122.5 72.6 47.8 37.5 138.2 112.7 109.8 CPUT Coal Puttalam � � 2,153.5 2,153.5 2,153.5 2,151.1 2,024.3 1,939.2 1,863.0 1,508.3 1,716.3 1,858.7 1,591.5 1,353.4 1,110.2 899.2 685.0 979.0 846.1 759.5 NCRE Existing and New RENW Renewables 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 New Thermal Power Plants GT1 Gas turbine 1 � � � � � � � � � � � 4.0 2.1 1.2 0.8 1.3 1.1 8.4 7.4 8.0 GT2 Gas turbine 2 � � � � � � � � � � � � � � � � � � � � GT3 Gas turbine 3 � � 38.7 1.1 140.3 0.2 0.2 0.5 1.2 0.6 5.7 47.7 23.8 13.6 9.5 13.2 10.7 64.2 55.7 57.8 CTRC Coal Trinco � � � � � 3,776.3 7,539.5 9,395.2 11,229.6 14,634.2 14,831.1 14,965.2 14,492.5 13,728.0 12,687.1 11,521.1 10,353.9 11,440.8 10,517.2 9,786.9 CCHF CC�Heavy Fuel � � � 3,295.8 3,342.8 1,496.8 736.3 759.5 780.4 348.1 807.1 1,311.6 875.1 578.4 410.4 285.4 212.9 566.1 464.6 423.6 CCDL CC�Diesel � � � � � � � � � � � � � � � � � � � � CCLN CC�LNG � � � � � � � � � � � � � � � � � � � � COSB Coal�Subcritical � � � � � 3,841.3 2,817.2 2,652.7 2,559.5 1,777.3 2,415.7 2,961.6 2,373.1 1,798.3 1,371.8 1,035.3 803.0 1,305.0 1,121.4 1,017.4 COSP Coal�Supercritical � � � � � � � � � � � � 4,169.3 8,338.6 12,506.7 16,646.5 20,691.2 20,767.8 24,768.9 28,666.4 PUMP Pumped Storage (generation) � � � � � � � � � � � � � � � � � � � � Thermal Total 5,363.2 6,581.8 7,967.9 9,113.3 10,666.6 12,298.3 13,825.6 15,463.4 17,173.2 18,870.6 20,604.1 22,480.6 24,488.6 26,585.6 28,722.7 30,967.3 33,277.6 35,794.0 38,410.3 41,346.2 Grand Total 9,738.7 10,957.3 12,343.4 13,910.1 15,463.4 17,095.1 18,622.4 20,260.2 21,970.0 23,667.4 25,400.9 27,277.4 29,285.4 31,382.4 33,519.5 35,764.1 38,074.4 40,590.8 43,207.1 46,143.0 Forecast demand 9,739.0 10,963.0 12,345.0 13,910.0 15,469.0 17,095.0 18,622.0 20,260.0 21,970.0 23,667.0 25,402.0 27,285.0 29,289.0 31,385.0 33,521.0 35,767.0 38,077.0 40,602.0 43,217.0 46,155.0 Unserved Energy 0.3 5.7 1.6 (0.1) 5.6 (0.1) (0.3) (0.2) 0.0 (0.4) 1.1 7.6 3.6 2.6 1.5 2.9 2.6 11.2 9.9 12.0 Sri Lanka: Environmental Issues in the Power Sector 180 ECA, RMA and ERM Detailed outputs from the model for the 15 cases Case 11: Energy Balance in GWh Case 11 High fuel prices 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 Existing and Committed Hydro plants Hydro1 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 Hydro2 � � � 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 New Hydro Plants Hydro3 Hydro4 Hydro Total 4,375.5 4,375.5 4,375.5 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 Existing and Committed Thermal plants GTSM Small Gas Turbines 1.6 5.4 � � � � � � � � � � � � � � � � � � DSP Diesel Sapugaskanda 435.4 418.7 347.1 384.3 � � � � � � � � � � � � � � � � DSPX Diesel Sapugaskanda�Extension 462.0 462.0 462.0 462.0 462.0 434.3 294.8 116.2 113.9 109.6 110.3 109.9 50.4 115.1 34.5 16.6 � � � � GT7 Gas Turbine 7 11.8 34.5 8.8 36.8 83.2 1.1 1.3 0.2 0.4 � � � � � � � � � � � DLDL Lakdhanavi Diesel 137.0 99.6 48.5 84.0 � � � � � � � � � � � � � � � � DAPL Asia Power Diesel 328.9 322.8 280.7 306.4 321.7 179.1 83.2 17.7 22.0 � � � � � � � � � � � CCKP Kelanitissa Combined Cycle 126.6 208.2 70.3 196.6 643.8 99.2 63.9 7.2 8.1 13.6 21.0 30.9 9.2 52.4 23.8 24.4 40.1 25.2 41.3 33.9 CAES AES Combined Cycle 902.6 573.6 273.4 481.1 1,047.2 323.4 221.9 34.6 41.3 66.0 66.3 88.6 25.2 129.6 55.7 � � � � � DCPL Colombo Power Diesel 417.6 388.2 299.6 348.0 403.2 195.5 � � � � � � � � � � � � � � DHOR Horana Diesel 152.8 124.9 66.2 102.1 � � � � � � � � � � � � � � � � DMAT Matara Diesel 151.2 119.3 57.4 � � � � � � � � � � � � � � � � � DPUT Puttalam Diesel 696.2 694.1 638.8 676.8 688.7 451.5 � � � � � � � � � � � � � � DEMB Embilipitiya Diesel 671.2 585.5 365.1 492.0 643.8 268.5 � � � � � � � � � � � � � � GTKW Kerawalapitiya Gas Turbine 398.4 � � � � � � � � � � � � � � � � � � � CCKW Kerawalapitiya Combined Cycle � 1,813.0 1,789.8 1,804.7 1,810.9 1,496.6 757.9 272.9 284.1 292.4 277.6 297.8 103.1 330.3 180.1 83.5 123.2 75.0 115.4 88.5 CPUT Coal Puttalam � � 2,153.5 2,153.5 2,153.5 2,153.5 2,149.6 1,997.7 1,879.4 1,756.9 1,660.5 1,571.5 1,143.6 1,435.8 1,078.0 772.0 1,083.3 854.5 1,132.0 977.9 NCRE Existing and New RENW Renewables 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 New Thermal Power Plants GT1 Gas turbine 1 � � � 3.1 20.0 0.3 0.5 0.1 0.1 0.7 1.1 2.2 0.9 6.3 3.5 4.1 8.8 5.8 13.9 11.8 GT2 Gas turbine 2 � � � � � � � � � � � � � � � � � � � � GT3 Gas turbine 3 � � � � 383.1 20.7 12.5 1.6 2.5 5.1 7.3 11.6 4.5 26.9 13.5 14.9 25.5 16.4 28.7 23.8 CTRC Coal Trinco � � � � � � 3,776.3 7,525.6 9,358.8 11,157.0 12,928.6 14,660.0 13,767.5 14,194.1 13,200.9 11,879.9 12,674.8 11,499.2 12,339.7 11,365.8 CCHF CC�Heavy Fuel � � � � � � � � � � � � � � � � � � � � CCDL CC�Diesel � � � � � � � � � � � � � � � � � � � � CCLN CC�LNG � � � � � � � � � � � � � � � � � � � � COSB Coal�Subcritical � � � � � 4,268.4 3,804.2 2,590.9 2,328.8 2,109.7 1,951.4 1,899.7 1,149.6 1,790.1 1,194.1 789.9 1,641.4 1,200.2 2,267.8 1,908.9 COSP Coal�Supercritical � � � � � � � � � � � � 4,169.3 4,169.3 8,338.6 12,502.5 12,506.3 16,643.1 16,662.6 20,761.8 PUMP Pumped Storage (generation) � � � � � � � � � � � � � � � � � � � � Thermal Total 5,363.2 6,319.5 7,330.8 8,001.1 9,130.9 10,361.6 11,635.7 13,034.4 14,509.1 15,980.7 17,493.8 19,141.9 20,893.0 22,719.7 24,592.3 26,557.4 28,573.2 30,789.2 33,071.0 35,642.0 Grand Total 9,738.7 10,695.0 11,706.3 12,797.9 13,927.7 15,158.4 16,432.5 17,831.2 19,305.9 20,777.5 22,290.6 23,938.7 25,689.8 27,516.5 29,389.1 31,354.2 33,370.0 35,586.0 37,867.8 40,438.8 Forecast demand 9,739.0 10,697.0 11,707.0 12,803.0 13,935.0 15,158.0 16,431.0 17,831.0 19,306.0 20,778.0 22,291.0 23,940.0 25,691.0 27,525.0 29,393.0 31,360.0 33,380.0 35,592.0 37,878.0 40,448.0 Unserved Energy 0.3 2.0 0.7 5.2 7.3 (0.4) (1.5) (0.2) 0.2 0.5 0.4 1.3 1.2 8.5 3.9 5.8 10.0 6.0 10.2 9.2 Sri Lanka: Environmental Issues in the Power Sector 181 ECA, RMA and ERM Detailed outputs from the model for the 15 cases Case 12: Energy Balance in GWh Case 12 Escalating fuel prices 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 Existing and Committed Hydro plants Hydro1 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 Hydro2 � � � 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 New Hydro Plants Hydro3 Hydro4 Hydro Total 4,375.5 4,375.5 4,375.5 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 Existing and Committed Thermal plants GTSM Small Gas Turbines 1.6 5.4 � � � � � � � � � � � � � � � � � � DSP Diesel Sapugaskanda 435.4 418.7 347.1 384.3 � � � � � � � � � � � � � � � � DSPX Diesel Sapugaskanda�Extension 462.0 462.0 462.0 462.0 462.0 434.3 294.8 116.2 113.9 109.6 110.3 109.9 50.4 115.1 34.5 16.6 � � � � GT7 Gas Turbine 7 11.8 34.5 8.8 36.8 83.2 1.1 1.3 0.2 0.4 � � � � � � � � � � � DLDL Lakdhanavi Diesel 137.0 99.6 48.5 84.0 � � � � � � � � � � � � � � � � DAPL Asia Power Diesel 328.9 322.8 280.7 306.4 321.7 179.1 83.2 17.7 22.0 � � � � � � � � � � � CCKP Kelanitissa Combined Cycle 126.6 208.2 70.3 196.6 643.8 99.2 63.9 7.2 8.1 13.6 21.0 30.9 9.2 52.4 23.8 24.4 15.5 66.1 43.5 36.3 CAES AES Combined Cycle 902.6 573.6 273.4 481.1 1,047.2 323.4 221.9 34.6 41.3 66.0 66.3 88.6 25.2 129.6 55.7 � � � � � DCPL Colombo Power Diesel 417.6 388.2 299.6 348.0 403.2 195.5 � � � � � � � � � � � � � � DHOR Horana Diesel 152.8 124.9 66.2 102.1 � � � � � � � � � � � � � � � � DMAT Matara Diesel 151.2 119.3 57.4 � � � � � � � � � � � � � � � � � DPUT Puttalam Diesel 696.2 694.1 638.8 676.8 688.7 451.5 � � � � � � � � � � � � � � DEMB Embilipitiya Diesel 671.2 585.5 365.1 492.0 643.8 268.5 � � � � � � � � � � � � � � GTKW Kerawalapitiya Gas Turbine 398.4 � � � � � � � � � � � � � � � � � � � CCKW Kerawalapitiya Combined Cycle � 1,813.0 1,789.8 1,804.7 1,810.9 1,496.6 757.9 272.9 284.1 292.4 277.6 297.8 103.1 330.3 180.1 83.5 47.7 191.2 122.5 92.7 CPUT Coal Puttalam � � 2,153.5 2,153.5 2,153.5 2,153.5 2,149.6 1,997.7 1,879.4 1,756.9 1,660.5 1,571.5 1,143.6 1,435.8 1,078.0 772.0 560.4 855.6 658.3 556.9 NCRE Existing and New RENW Renewables 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 New Thermal Power Plants GT1 Gas turbine 1 � � � 3.1 20.0 0.3 0.5 0.1 0.1 0.7 1.1 2.2 0.9 6.3 3.5 4.1 2.6 8.7 6.2 5.3 GT2 Gas turbine 2 � � � � � � � � � � � � � � � � � 6.8 4.8 4.1 GT3 Gas turbine 3 � � � � 383.1 20.7 12.5 1.6 2.5 5.1 7.3 11.6 4.5 26.9 13.5 14.9 9.7 57.9 40.1 33.4 CTRC Coal Trinco � � � � � � 3,776.3 7,525.6 9,358.8 11,157.0 12,928.6 14,660.0 13,767.5 14,194.1 13,200.9 11,879.9 10,376.1 11,490.7 10,308.3 9,253.6 CCHF CC�Heavy Fuel � � � � � � � � � � � � � � � � � � � � CCDL CC�Diesel � � � � � � � � � � � � � � � � � � � � CCLN CC�LNG � � � � � � � � � � � � � � � � � � � � COSB Coal�Subcritical � � � � � 4,268.4 3,804.2 2,590.9 2,328.8 2,109.7 1,951.4 1,899.7 1,149.6 1,790.1 1,194.1 789.9 494.0 995.0 741.0 620.3 COSP Coal�Supercritical � � � � � � � � � � � � 4,169.3 4,169.3 8,338.6 12,502.5 16,604.1 16,643.1 20,679.1 24,571.9 PUMP Pumped Storage (generation) � � � � � � � � � � � � � � � � � � � � Thermal Total 5,363.2 6,319.5 7,330.8 8,001.1 9,130.9 10,361.6 11,635.7 13,034.4 14,509.1 15,980.7 17,493.8 19,141.9 20,893.0 22,719.7 24,592.3 26,557.4 28,579.8 30,784.9 33,073.6 35,644.3 Grand Total 9,738.7 10,695.0 11,706.3 12,797.9 13,927.7 15,158.4 16,432.5 17,831.2 19,305.9 20,777.5 22,290.6 23,938.7 25,689.8 27,516.5 29,389.1 31,354.2 33,376.6 35,581.7 37,870.4 40,441.1 Forecast demand 9,739.0 10,697.0 11,707.0 12,803.0 13,935.0 15,158.0 16,431.0 17,831.0 19,306.0 20,778.0 22,291.0 23,940.0 25,691.0 27,525.0 29,393.0 31,360.0 33,380.0 35,592.0 37,878.0 40,448.0 Unserved Energy 0.3 2.0 0.7 5.2 7.3 (0.4) (1.5) (0.2) 0.2 0.5 0.4 1.3 1.2 8.5 3.9 5.8 3.4 10.3 7.6 6.9 Sri Lanka: Environmental Issues in the Power Sector 182 ECA, RMA and ERM Detailed outputs from the model for the 15 cases Case 13: Energy Balance in GWh Case 13 Lower discount rate 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 Existing and Committed Hydro plants Hydro1 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 Hydro2 � � � 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 New Hydro Plants Hydro3 � � � 236.1 236.1 236.1 236.1 236.1 236.1 236.1 236.1 236.1 236.1 236.1 236.1 236.1 236.1 236.1 Hydro4 � � � � 210.0 210.0 210.0 210.0 210.0 210.0 210.0 210.0 210.0 210.0 210.0 210.0 210.0 210.0 Hydro Total 4,375.5 4,375.5 4,375.5 4,796.8 4,796.8 5,032.9 5,242.9 5,242.9 5,242.9 5,242.9 5,242.9 5,242.9 5,242.9 5,242.9 5,242.9 5,242.9 5,242.9 5,242.9 5,242.9 5,242.9 Existing and Committed Thermal plants GTSM Small Gas Turbines 1.64 5.38 0 0 0 0 0 � � � � � � � � � � � � � DSP Diesel Sapugaskanda 435.43 418.68 347.07 384.68 0 0 0 � � � � � � � � � � � � � DSPX Diesel Sapugaskanda�Extension 462.01 462.01 461.98 461.98 462.01 426.11 260.47 88.6 90.0 88.9 94.5 97.0 36.9 103.6 26.1 11.3 � � � � GT7 Gas Turbine 7 11.83 34.5 8.78 7.26 83.24 0.56 0.45 0.0 0.1 � � � � � � � � � � � DLDL Lakdhanavi Diesel 137.02 99.6 48.54 85.53 0 0 0 � � � � � � � � � � � � � DAPL Asia Power Diesel 328.91 322.83 280.66 307.89 321.7 161.2 65.27 12.8 12.1 � � � � � � � � � � � CCKP Kelanitissa Combined Cycle 126.57 208.19 70.28 185.28 643.8 78.14 27.63 2.0 3.1 6.0 8.5 13.2 5.0 30.7 14.0 15.2 9.7 45.4 30.3 25.4 CAES AES Combined Cycle 902.57 573.58 273.44 488.91 1047.2 270.9 160.69 17.6 16.8 30.4 37.1 48.4 13.2 85.5 33.7 � � � � � DCPL Colombo Power Diesel 417.63 388.16 299.58 347.92 403.17 183.49 0 � � � � � � � � � � � � � DHOR Horana Diesel 152.8 124.93 66.21 103.37 0 0 0 � � � � � � � � � � � � � DMAT Matara Diesel 151.22 119.32 57.38 0 0 0 0 � � � � � � � � � � � � � DPUT Puttalam Diesel 696.2 694.1 638.83 674.6 688.68 420.49 0 � � � � � � � � � � � � � DEMB Embilipitiya Diesel 671.23 585.5 365.07 494.54 643.82 242.46 0 � � � � � � � � � � � � � GTKW Kerawalapitiya Gas Turbine 398.39 0 0 0 0 0 0 � � � � � � � � � � � � � CCKW Kerawalapitiya Combined Cycle 0 1812.98 1789.82 1804.74 1810.91 1448.05 626.2 191.5 200.3 205.2 197.7 241.3 59.1 276.0 122.6 50.9 31.1 140.0 87.9 67.8 CPUT Coal Puttalam 0 0 2153.45 2153.47 2153.47 2153.47 2145.51 1,943.2 1,822.0 1,696.7 1,589.7 1,508.0 1,078.6 1,369.6 1,019.7 728.1 526.4 817.6 624.5 524.4 NCRE Existing and New RENW Renewables 469.75 469.75 469.75 469.75 469.75 469.75 469.75 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 New Thermal Power Plants GT1 Gas turbine 1 � � � 0 20.03 0.15 0.12 0.0 0.0 0.3 0.4 0.8 0.4 3.5 2.0 2.4 1.5 5.8 4.1 3.6 GT2 Gas turbine 2 � � � 0 0 0 0 � � � � � � � � � � � � � GT3 Gas turbine 3 � � � 0 383.14 13.69 4.83 0.6 0.9 2.0 3.1 5.5 2.2 14.9 8.0 9.2 6.0 38.3 26.5 22.4 CTRC Coal Trinco � � � 34.54 0 0 3776.22 7,509.5 9,331.3 11,105.9 12,861.2 14,578.3 13,585.1 14,074.2 13,027.5 11,657.3 10,125.3 11,281.7 10,071.4 9,045.3 CCHF CC�Heavy Fuel � � � 0 0 0 0 � � � � � � � � � � � � � CCDL CC�Diesel � � � 0 0 0 0 � � � � � � � � � � � � � CCLN CC�LNG � � � 0 0 0 0 � � � � � � � � � � � � � COSB Coal�Subcritical � � � 0 0 4257.11 3652.61 2,352.9 2,116.7 1,929.9 1,786.3 1,734.7 1,028.0 1,680.7 1,086.8 670.6 381.6 908.4 666.0 524.7 COSP Coal�Supercritical � � � 0 0 0 0 � � � � � 4,169.3 4,169.3 8,338.6 12,499.6 16,584.2 16,632.4 20,647.6 24,515.3 PUMP Pumped Storage (generation) 0 0 0 0 0 0 0 � � � � � � � � � � � � � Thermal Total 5,363.2 6,319.5 7,330.8 8,004.5 9,130.9 10,125.6 11,189.8 12,588.4 14,063.0 15,535.0 17,048.2 18,697.0 20,447.5 22,277.9 24,148.6 26,114.3 28,135.5 30,339.4 32,628.0 35,198.6 Grand Total 9,738.7 10,695.0 11,706.3 12,801.3 13,927.7 15,158.5 16,432.7 17,831.3 19,305.9 20,777.9 22,291.1 23,939.9 25,690.4 27,520.8 29,391.5 31,357.2 33,378.4 35,582.3 37,870.9 40,441.5 Forecast demand 9,739.0 10,697.0 11,707.0 12,803.0 13,935.0 15,158.0 16,431.0 17,831.0 19,306.0 20,778.0 22,291.0 23,940.0 25,691.0 27,525.0 29,393.0 31,360.0 33,380.0 35,592.0 37,878.0 40,448.0 Unserved Energy 0.3 2.0 0.7 1.7 7.3 (0.5) (1.7) (0.3) 0.1 0.2 (0.1) 0.1 0.6 4.2 1.5 2.8 1.6 9.7 7.2 6.5 Sri Lanka: Environmental Issues in the Power Sector 183 ECA, RMA and ERM Detailed outputs from the model for the 15 cases Case 14: Energy Balance in GWh Case 14 NCRE forced with fuel price esc. 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 Existing and Committed Hydro plants Hydro1 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 Hydro2 � � � 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 New Hydro Plants Hydro3 Hydro4 Hydro Total 4,375.5 4,375.5 4,375.5 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 Existing and Committed Thermal plants GTSM Small Gas Turbines 1.5 4.1 � � � � � � � � � � � � � � � � � � DSP Diesel Sapugaskanda 435.4 414.6 323.2 360.8 � � � � � � � � � � � � � � � � DSPX Diesel Sapugaskanda�Extension 462.0 462.0 461.9 462.0 462.0 396.9 196.8 56.3 131.0 119.6 45.9 112.4 112.6 176.0 56.5 55.5 � � � � GT7 Gas Turbine 7 10.9 24.4 4.7 15.4 100.0 0.9 0.8 0.1 1.2 � � � � � � � � � � � DLDL Lakdhanavi Diesel 136.5 91.2 41.2 61.4 � � � � � � � � � � � � � � � � DAPL Asia Power Diesel 328.9 319.6 266.7 287.0 311.4 131.4 44.9 5.0 28.8 � � � � � � � � � � � CCKP Kelanitissa Combined Cycle 121.1 177.7 47.9 135.2 469.3 30.7 11.2 1.3 13.1 20.1 4.2 29.5 38.7 61.4 22.9 61.4 32.2 46.6 29.1 49.4 CAES AES Combined Cycle 889.0 515.6 224.1 381.1 884.5 154.5 82.5 7.5 61.3 81.5 14.5 91.0 104.8 145.9 51.4 � � � � � DCPL Colombo Power Diesel 417.1 379.5 258.3 306.5 383.9 141.5 � � � � � � � � � � � � � � DHOR Horana Diesel 152.2 118.8 53.9 76.3 � � � � � � � � � � � � � � � � DMAT Matara Diesel 150.2 108.0 47.7 � � � � � � � � � � � � � � � � � DPUT Puttalam Diesel 696.2 690.7 618.1 654.9 676.8 339.8 � � � � � � � � � � � � � � DEMB Embilipitiya Diesel 668.8 551.5 300.1 411.9 589.3 179.9 � � � � � � � � � � � � � � GTKW Kerawalapitiya Gas Turbine 387.7 � � � � � � � � � � � � � � � � � � � CCKW Kerawalapitiya Combined Cycle � 1,812.6 1,771.2 1,793.4 1,803.5 1,261.6 432.4 86.7 324.5 310.2 85.0 296.4 325.9 363.4 163.4 195.7 101.9 136.0 82.1 128.4 CPUT Coal Puttalam � � 2,153.4 2,153.5 2,153.5 2,153.5 2,126.7 1,780.4 1,940.3 1,810.3 1,318.4 1,581.4 1,494.6 1,640.3 1,757.8 1,868.6 1,615.3 1,734.0 1,541.6 1,660.8 NCRE Existing and New RENW Renewables 505.9 650.4 758.8 903.4 1,120.2 1,373.1 1,626.1 1,806.8 1,951.3 2,059.7 2,204.2 2,312.6 2,493.3 2,710.1 2,926.9 3,107.6 3,324.4 3,469.0 3,649.6 3,866.4 New Thermal Power Plants GT1 Gas turbine 1 � � � � 33.8 0.3 0.3 0.0 0.6 2.6 0.5 5.3 8.1 9.0 3.0 15.1 8.0 13.8 8.3 13.1 GT2 Gas turbine 2 � � � � � � � � � � � � � � � � � � � 7.8 GT3 Gas turbine 3 � � � � 145.0 4.1 1.9 0.3 2.6 4.5 1.0 8.0 11.4 31.9 11.6 36.3 19.3 31.4 18.9 35.8 CTRC Coal Trinco � � � � � � 3,775.7 7,445.8 7,497.1 9,300.6 12,542.7 12,785.0 14,460.9 14,680.0 14,830.6 14,942.0 14,435.5 14,665.0 14,062.5 14,377.8 CCHF CC�Heavy Fuel � � � � � � � � � � � � � 504.7 326.8 312.3 197.6 240.5 160.6 218.9 CCDL CC�Diesel � � � � � � � � � � � � � � � � � � � � CCLN CC�LNG � � � � � � � � � � � � � � � � � � � � COSB Coal�Subcritical � � � � � 4,193.6 3,336.4 1,844.3 2,557.1 2,270.8 1,277.8 1,918.9 1,838.2 2,398.9 4,444.1 5,962.3 4,676.3 6,282.3 5,185.0 6,945.6 COSP Coal�Supercritical � � � � � � � � � � � � � � � � 4,169.3 4,169.3 8,338.5 8,338.5 PUMP Pumped Storage (generation) � � � � � � � � � � � � � � � � � � � � Thermal Total 5,363.2 6,320.6 7,331.1 8,002.7 9,132.9 10,361.6 11,635.7 13,034.4 14,508.8 15,979.9 17,494.2 19,140.5 20,888.5 22,721.4 24,595.1 26,556.7 28,579.6 30,788.0 33,076.3 35,642.4 Grand Total 9,738.7 10,696.1 11,706.6 12,799.5 13,929.7 15,158.4 16,432.5 17,831.2 19,305.6 20,776.7 22,291.0 23,937.3 25,685.3 27,518.2 29,391.9 31,353.5 33,376.4 35,584.8 37,873.1 40,439.2 Forecast demand 9,739.0 10,697.0 11,707.0 12,803.0 13,935.0 15,158.0 16,431.0 17,831.0 19,306.0 20,778.0 22,291.0 23,940.0 25,691.0 27,525.0 29,393.0 31,360.0 33,380.0 35,592.0 37,878.0 40,448.0 Unserved Energy 0.3 0.9 0.4 3.5 5.3 (0.4) (1.5) (0.2) 0.4 1.3 (0.0) 2.7 5.7 6.8 1.2 6.5 3.6 7.2 4.9 8.8 Sri Lanka: Environmental Issues in the Power Sector 184 ECA, RMA and ERM Detailed outputs from the model for the 15 cases Case 15: Energy Balance in GWh Case 15 Pumped storage allowed with DSM 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 Existing and Committed Hydro plants Hydro1 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 4,375.5 Hydro2 � � � 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 421.3 New Hydro Plants Hydro3 Hydro4 Hydro Total 4,375.5 4,375.5 4,375.5 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 4,796.8 Existing and Committed Thermal plants GTSM Small Gas Turbines 1.8 4.2 � � � � � � � � � � � � � � � � � � DSP Diesel Sapugaskanda 435.4 414.9 330.4 365.4 � � � � � � � � � � � � � � � � DSPX Diesel Sapugaskanda�Extension 462.0 462.0 461.7 461.9 461.9 416.5 266.6 85.1 80.1 78.6 151.0 80.9 161.5 100.1 19.4 43.4 � � � � GT7 Gas Turbine 7 11.5 23.5 4.4 17.7 43.2 0.1 0.1 0.0 0.0 � � � � � � � � � � � DLDL Lakdhanavi Diesel 137.3 97.1 44.2 67.7 � � � � � � � � � � � � � � � � DAPL Asia Power Diesel 328.9 321.0 268.2 291.2 314.0 150.6 58.5 6.2 6.6 � � � � � � � � � � � CCKP Kelanitissa Combined Cycle 128.7 195.2 46.2 156.0 520.0 38.0 15.6 0.7 1.1 2.3 40.5 7.1 72.6 18.5 8.2 40.2 19.1 69.2 21.3 14.1 CAES AES Combined Cycle 912.5 548.8 220.5 392.9 945.9 207.4 138.7 9.4 10.9 14.7 160.0 33.9 199.9 51.5 22.3 � � � � � DCPL Colombo Power Diesel 418.0 382.5 284.4 321.6 389.4 171.8 � � � � � � � � � � � � � � DHOR Horana Diesel 153.5 121.2 59.2 84.3 � � � � � � � � � � � � � � � � DMAT Matara Diesel 151.6 116.7 53.1 � � � � � � � � � � � � � � � � � DPUT Puttalam Diesel 696.2 692.5 617.1 660.5 678.8 401.8 � � � � � � � � � � � � � � DEMB Embilipitiya Diesel 672.3 572.3 332.2 442.5 610.8 224.1 � � � � � � � � � � � � � � GTKW Kerawalapitiya Gas Turbine 411.1 � � � � � � � � � � � � � � � � � � � CCKW Kerawalapitiya Combined Cycle � 1,812.6 1,764.7 1,791.4 1,804.7 1,400.6 607.0 145.0 171.1 185.7 461.9 184.2 481.1 228.3 74.6 209.2 117.4 237.9 190.1 198.3 CPUT Coal Puttalam � � 2,153.4 2,153.4 2,153.5 2,153.5 2,141.1 1,923.7 1,795.1 1,675.7 1,840.5 1,503.9 1,679.5 1,399.8 1,071.9 1,332.7 1,094.1 1,324.5 1,141.9 981.8 NCRE Existing and New RENW Renewables 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 469.8 New Thermal Power Plants GT1 Gas turbine 1 � � � � � � � � � � � � 1.5 0.7 0.4 1.5 0.9 1.9 1.2 0.9 GT2 Gas turbine 2 � � � � � � � � � � � � � � � � � � � � GT3 Gas turbine 3 � � � � 254.7 5.8 1.3 0.2 0.3 0.6 8.0 2.0 26.0 8.0 4.2 15.4 9.2 22.0 11.6 8.8 CTRC Coal Trinco � � � � � � 3,776.2 7,497.9 9,306.7 11,072.3 11,186.8 14,523.8 14,748.3 14,024.9 12,984.4 13,912.6 12,678.3 13,930.1 12,699.8 11,448.0 CCHF CC�Heavy Fuel � � � � � � � � � � � � � � � � � � � � CCDL CC�Diesel � � � � � � � � � � � � � � � � � � � � CCLN CC�LNG � � � � � � � � � � � � � � � � � � � � COSB Coal�Subcritical � � � � � 4,230.2 3,637.8 2,340.4 2,128.6 1,926.8 2,660.8 1,782.7 2,477.7 1,735.6 1,039.4 1,745.2 1,225.7 1,891.7 1,494.1 1,172.3 COSP Coal�Supercritical � � � � � � � � � � � � � 4,169.3 8,338.6 8,338.6 12,508.0 12,507.9 16,677.2 20,836.7 PUMP Pumped Storage (generation) � � � � � � � � � � � � � � � 267.3 135.2 582.8 397.9 247.1 Thermal Total 5,390.5 6,234.2 7,109.4 7,676.3 8,646.7 9,870.0 11,112.5 12,478.4 13,970.2 15,426.5 16,979.2 18,588.2 20,317.8 22,206.3 24,033.1 26,375.8 28,257.6 31,037.6 33,104.8 35,377.6 Grand Total 9,766.0 10,609.7 11,484.9 12,473.1 13,443.5 14,666.8 15,909.3 17,275.2 18,767.0 20,223.3 21,776.0 23,385.0 25,114.6 27,003.1 28,829.9 31,172.6 33,054.4 35,834.4 37,901.6 40,174.4 Forecast demand 9,764.0 10,607.7 11,491.2 12,469.6 13,446.7 14,670.2 15,919.4 17,286.8 18,776.4 20,234.0 21,765.3 23,390.2 25,130.2 26,991.6 28,841.3 30,787.1 32,847.0 35,034.8 37,362.6 39,841.7 Unserved Energy (2.0) (2.0) 6.3 (3.5) 3.3 3.4 10.0 11.7 9.4 10.7 (10.8) 5.2 15.6 (11.6) 11.3 (385.5) (207.5) (799.6) (538.9) (332.7) Sri Lanka: Environmental Issues in the Power Sector 185 ECA, RMA and ERM Detailed outputs from the model for the 15 cases Case 1: Fuel consumption in MT Case 1 Base Case 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 Existing and Committed Hydro plants Hydro1 � � � � � � � � � � � � � � � � � � � � Hydro2 � � � � � � � � � � � � � � � � � � � � New Hydro Plants Hydro3 � � � � � � � � � � � � � � � � � � � � Hydro4 � � � � � � � � � � � � � � � � � � � � Hydro Total � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � Existing and Committed Thermal plants GTSM Small Gas Turbines 686 2,245 � � � � � � � � � � � � � � � � � � DSP Diesel Sapugaskanda 99,963 96,116 79,677 88,222 � � � � � � � � � � � � � � � � DSPX Diesel Sapugaskanda�Extension 97,637 97,637 97,630 97,631 97,637 91,780 62,295 24,547 24,071 23,151 23,307 23,228 10,652 24,318 7,297 3,517 � � � � GT7 Gas Turbine 7 3,065 8,939 2,275 9,520 21,565 271 334 51 96 � � � � � � � � � � � DLDL Lakdhanavi Diesel 32,242 23,436 11,422 19,772 � � � � � � � � � � � � � � � � DAPL Asia Power Diesel 76,974 75,551 65,683 71,706 75,287 41,906 19,462 4,150 5,140 � � � � � � � � � � � CCKP Kelanitissa Combined Cycle 21,680 35,660 12,038 33,667 110,277 16,990 10,939 1,233 1,395 2,325 3,594 5,298 1,579 8,974 4,071 4,184 2,647 11,319 7,458 13,265 CAES AES Combined Cycle 162,589 103,325 49,257 86,672 188,643 58,259 39,973 6,233 7,438 11,889 11,934 15,957 4,535 23,352 10,031 � � � � � DCPL Colombo Power Diesel 94,394 87,732 67,712 78,662 91,125 44,190 � � � � � � � � � � � � � � DHOR Horana Diesel 35,989 29,424 15,594 24,038 � � � � � � � � � � � � � � � � DMAT Matara Diesel 35,805 28,252 13,586 � � � � � � � � � � � � � � � � � DPUT Puttalam Diesel 140,910 140,486 129,299 136,990 139,388 91,379 � � � � � � � � � � � � � � DEMB Embilipitiya Diesel 155,221 135,398 84,422 113,776 148,885 62,088 � � � � � � � � � � � � � � GTKW Kerawalapitiya Gas Turbine 94,104 � � � � � � � � � � � � � � � � � � � CCKW Kerawalapitiya Combined Cycle � 394,051 389,017 392,245 393,602 325,276 164,729 59,322 61,740 63,551 60,337 64,719 22,402 71,797 39,138 18,139 10,375 41,564 26,621 43,219 CPUT Coal Puttalam � � 502,658 502,664 502,664 502,664 501,753 466,295 438,695 410,098 387,603 366,826 266,945 335,135 251,621 180,189 130,813 199,714 153,662 228,196 NCRE Existing and New RENW Renewables � � � � � � � � � � � � � � � � � � � � New Thermal Power Plants GT1 Gas turbine 1 � � � 909 5,873 99 140 15 32 209 330 634 254 1,846 1,022 1,188 768 2,305 1,629 2,388 GT2 Gas turbine 2 � � � � � � � � � � � � � � � � � � � � GT3 Gas turbine 3 � � � � 106,942 5,772 3,480 453 695 1,429 2,034 3,243 1,263 7,520 3,763 4,160 2,706 18,667 12,960 27,143 CTRC Coal Trinco � � � � � � 1,389,180 2,768,439 3,442,802 4,104,309 4,756,038 5,392,960 5,064,644 5,221,577 4,856,223 4,370,248 3,817,042 4,227,066 3,792,124 4,189,402 CCHF CC�Heavy Fuel � � � � � � � � � � � � � � � � � � � � CCDL CC�Diesel � � � � � � � � � � � � � � � � � � � � CCLN CC�LNG � � � � � � � � � � � � � � � � � � � � COSB Coal�Subcritical � � � � � 1,570,207 1,399,455 953,124 856,700 776,093 717,842 698,854 422,913 658,535 439,256 290,587 181,724 366,032 272,582 611,005 COSP Coal�Supercritical � � � � � � � � � � � � 1,391,293 1,391,293 2,782,587 4,172,071 5,540,780 5,553,814 6,900,631 6,928,205 PUMP Pumped Storage (generation) � � � � � � � � � � � � � � � � � � � � Total Fuel Use 1,051,259 1,258,252 1,520,269 1,656,474 1,881,887 2,810,880 3,591,741 4,283,863 4,838,804 5,393,053 5,963,021 6,571,719 7,186,481 7,744,348 8,395,009 9,044,283 9,686,856 10,420,480 11,167,667 12,042,823 Total themal generation exc. NCRE 4,893 5,850 6,861 7,531 8,661 9,892 11,166 12,565 14,039 15,511 17,024 18,672 20,423 22,250 24,123 26,088 28,110 30,316 32,605 35,170 Spec. fuel consumpion (kg/kWh) 0.215 0.215 0.222 0.220 0.217 0.284 0.322 0.341 0.345 0.348 0.350 0.352 0.352 0.348 0.348 0.347 0.345 0.344 0.343 0.342 Sri Lanka: Environmental Issues in the Power Sector 186 ECA, RMA and ERM Detailed outputs from the model for the 15 cases Case 2: Fuel consumption in MT Case 2 LNG Forced 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 Existing and Committed Hydro plants Hydro1 � � � � � � � � � � � � � � � � � � � � Hydro2 � � � � � � � � � � � � � � � � � � � � New Hydro Plants Hydro3 � � � � � � � � � � � � � � � � � � � � Hydro4 � � � � � � � � � � � � � � � � � � � � Hydro Total � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � Existing and Committed Thermal plants GTSM Small Gas Turbines 686 2,245 � � � � � � � � � � � � � � � � � � DSP Diesel Sapugaskanda 99,963 96,116 79,677 88,222 � � � � � � � � � � � � � � � � DSPX Diesel Sapugaskanda�Extension 97,637 97,637 97,630 97,631 97,637 76,659 62,295 78,202 39,008 32,592 29,114 27,041 27,064 27,112 14,006 8,910 � � � � GT7 Gas Turbine 7 3,065 8,939 2,275 9,520 21,565 29 334 4,848 597 � � � � � � � � � � � DLDL Lakdhanavi Diesel 32,242 23,436 11,422 19,772 � � � � � � � � � � � � � � � � DAPL Asia Power Diesel 76,974 75,551 65,683 71,706 75,287 20,132 19,462 37,450 12,919 � � � � � � � � � � � CCKP Kelanitissa Combined Cycle 21,680 35,660 12,038 33,667 110,277 1,596 10,939 43,355 6,388 9,388 8,702 9,134 10,891 12,859 18,282 16,044 23,751 12,304 18,092 13,513 CAES AES Combined Cycle 162,589 103,325 49,257 86,672 188,643 15,692 39,973 85,205 22,389 26,947 25,036 24,995 27,431 31,047 36,201 � � � � � DCPL Colombo Power Diesel 94,394 87,732 67,712 78,662 91,125 19,621 � � � � � � � � � � � � � � DHOR Horana Diesel 35,989 29,424 15,594 24,038 � � � � � � � � � � � � � � � � DMAT Matara Diesel 35,805 28,252 13,586 � � � � � � � � � � � � � � � � � DPUT Puttalam Diesel 140,910 140,486 129,299 136,990 139,388 47,493 � � � � � � � � � � � � � � DEMB Embilipitiya Diesel 155,221 135,398 84,422 113,776 148,885 23,147 � � � � � � � � � � � � � � GTKW Kerawalapitiya Gas Turbine 94,104 � � � � � � � � � � � � � � � � � � � CCKW Kerawalapitiya Combined Cycle � 394,051 389,017 392,245 393,602 226,959 164,729 257,799 109,223 92,965 86,503 85,319 84,323 83,755 93,002 58,265 67,561 44,535 56,773 43,575 CPUT Coal Puttalam � � 502,658 502,664 502,664 499,470 501,753 502,493 502,604 502,656 502,663 502,664 502,664 502,664 502,664 502,664 502,664 502,664 502,664 502,664 NCRE Existing and New RENW Renewables � � � � � � � � � � � � � � � � � � � � New Thermal Power Plants GT1 Gas turbine 1 � � � 909 5,873 12 140 1,921 303 1,044 1,255 1,691 1,666 1,535 1,684 1,772 1,770 1,081 2,576 2,076 GT2 Gas turbine 2 � � � � � � � � � � � � 1,696 1,544 1,646 1,705 6,692 4,184 7,246 5,859 GT3 Gas turbine 3 � � � � 106,942 372 3,480 35,978 3,631 5,234 5,578 6,710 8,698 14,737 24,945 23,863 36,451 22,449 33,778 26,997 CTRC Coal Trinco � � � � � 1,389,144 1,389,180 1,389,187 1,389,186 1,389,187 1,389,187 1,389,187 1,389,187 1,389,187 1,389,187 1,389,186 1,389,187 1,389,187 1,389,187 1,389,187 CCHF CC�Heavy Fuel � � � � � � � � � � � � � � � � � � � � CCDL CC�Diesel � � � � � � � � � � � � � � � � � � � � CCLN CC�LNG � � � � � � � � 444,995 665,135 888,687 1,127,412 1,377,242 1,637,849 1,899,563 2,245,903 2,525,572 2,884,213 3,196,427 3,590,143 COSB Coal�Subcritical � � � � � 722,357 1,399,455 1,484,653 1,526,007 1,554,106 1,570,140 1,578,584 1,582,463 1,583,904 1,584,304 1,584,390 1,584,398 1,584,397 1,584,397 1,584,397 COSP Coal�Supercritical � � � � � � � � � � � � � � � � � � � � PUMP Pumped Storage (generation) � � � � � � � � � � � � � � � � � � � � Total Fuel Use 1,051,259 1,258,252 1,520,269 1,656,474 1,881,887 3,042,682 3,591,741 3,921,090 4,057,249 4,279,254 4,506,864 4,752,736 5,013,325 5,286,192 5,565,482 5,832,702 6,138,045 6,445,013 6,791,139 7,158,409 Total themal generation exc. NCRE 4,893 5,850 6,861 7,531 8,661 9,892 11,166 12,561 14,039 15,508 17,020 18,667 20,417 22,251 24,119 26,084 28,104 30,320 32,600 35,172 Spec. fuel consumpion (kg/kWh) 0.215 0.215 0.222 0.220 0.217 0.308 0.322 0.312 0.289 0.276 0.265 0.255 0.246 0.238 0.231 0.224 0.218 0.213 0.208 0.204 Sri Lanka: Environmental Issues in the Power Sector 187 ECA, RMA and ERM Detailed outputs from the model for the 15 cases Case 3: Fuel consumption in MT Case 3 Hydro Forced 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 Existing and Committed Hydro plants Hydro1 � � � � � � � � � � � � � � � � � � � � Hydro2 � � � � � � � � � � � � � � � � � � � � New Hydro Plants Hydro3 � � � � � � � � � � � � � � � � � � � � Hydro4 � � � � � � � � � � � � � � � � � � � � Hydro Total � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � Existing and Committed Thermal plants GTSM Small Gas Turbines 686 2,245 � � � � � � � � � � � � � � � � � � DSP Diesel Sapugaskanda 99,963 96,116 79,677 88,080 � � � � � � � � � � � � � � � � DSPX Diesel Sapugaskanda�Extension 97,637 97,637 97,630 97,631 97,637 89,805 46,356 37,999 34,695 31,791 28,618 30,312 32,262 18,495 16,816 10,863 � � � � GT7 Gas Turbine 7 3,065 8,939 2,275 9,807 7,222 43 7 8 18 � � � � � � � � � � � DLDL Lakdhanavi Diesel 32,242 23,436 11,422 19,800 � � � � � � � � � � � � � � � � DAPL Asia Power Diesel 76,974 75,551 65,683 71,924 75,227 36,782 11,226 9,410 9,612 � � � � � � � � � � � CCKP Kelanitissa Combined Cycle 21,680 35,660 12,038 35,324 110,653 14,127 1,357 2,447 2,524 4,068 4,171 6,370 9,208 2,316 19,252 16,301 7,432 4,450 18,377 13,705 CAES AES Combined Cycle 162,589 103,325 49,257 85,433 189,097 48,735 19,111 12,596 15,318 17,427 16,746 25,470 29,331 7,365 41,726 � � � � � DCPL Colombo Power Diesel 94,394 87,732 67,712 78,512 91,007 40,771 � � � � � � � � � � � � � � DHOR Horana Diesel 35,989 29,424 15,594 23,578 � � � � � � � � � � � � � � � � DMAT Matara Diesel 35,805 28,252 13,586 � � � � � � � � � � � � � � � � � DPUT Puttalam Diesel 140,910 140,486 129,299 137,217 139,288 85,362 � � � � � � � � � � � � � � DEMB Embilipitiya Diesel 155,221 135,398 84,422 113,131 146,370 56,294 � � � � � � � � � � � � � � GTKW Kerawalapitiya Gas Turbine 94,104 � � � � � � � � � � � � � � � � � � � CCKW Kerawalapitiya Combined Cycle � 394,051 389,017 392,292 393,596 315,150 113,993 96,789 85,745 81,313 85,189 84,015 94,367 43,017 107,126 61,164 32,251 18,122 65,608 49,185 CPUT Coal Puttalam � � 502,658 502,664 502,664 502,664 499,073 488,855 471,828 449,734 424,419 404,405 388,696 315,608 358,358 300,703 233,348 182,346 252,185 218,930 NCRE Existing and New RENW Renewables � � � � � � � � � � � � � � � � � � � � New Thermal Power Plants GT1 Gas turbine 1 � � � � � � � � � � � � � � 2,359 2,660 1,720 1,152 2,376 2,035 GT2 Gas turbine 2 � � � � � � � � � � � � � � � � � � 4,094 3,435 GT3 Gas turbine 3 � � � � 130,008 4,023 278 353 563 1,575 1,950 3,381 5,663 2,250 16,796 15,780 9,012 5,796 31,158 25,164 CTRC Coal Trinco � � � � � � 1,389,118 2,082,167 2,769,143 3,447,465 4,112,804 4,773,050 5,419,422 5,148,739 5,276,950 4,965,052 4,559,480 4,102,506 4,438,574 4,079,444 CCHF CC�Heavy Fuel � � � � � � � � � � � � � � � � � � � � CCDL CC�Diesel � � � � � � � � � � � � � � � � � � � � CCLN CC�LNG � � � � � � � � � � � � � � � � � � � � COSB Coal�Subcritical � � � � � 1,566,063 1,275,788 1,170,726 1,071,169 987,810 918,662 870,975 854,754 557,134 812,602 584,846 405,680 277,384 508,294 413,736 COSP Coal�Supercritical � � � � � � � � � � � � � 1,391,293 1,391,293 2,782,587 4,172,506 5,547,339 5,557,075 6,916,755 PUMP Pumped Storage (generation) � � � � � � � � � � � � � � � � � � � � Total Fuel Use 1,051,259 1,258,252 1,520,269 1,655,390 1,882,770 2,759,818 3,356,308 3,901,349 4,460,615 5,021,182 5,592,558 6,197,978 6,833,704 7,486,218 8,043,277 8,739,955 9,421,428 10,139,095 10,877,739 11,722,389 Total themal generation exc. NCRE 4,893 5,850 6,861 7,532 8,661 9,656 10,289 11,688 13,162 14,634 16,147 17,796 19,544 21,380 23,243 25,207 27,230 29,445 31,724 34,295 Spec. fuel consumpion (kg/kWh) 0.215 0.215 0.222 0.220 0.217 0.286 0.326 0.334 0.339 0.343 0.346 0.348 0.350 0.350 0.346 0.347 0.346 0.344 0.343 0.342 Sri Lanka: Environmental Issues in the Power Sector 188 ECA, RMA and ERM Detailed outputs from the model for the 15 cases Case 4: Fuel consumption in MT Case 4 NCRE Target 10% by 2015 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 Existing and Committed Hydro plants Hydro1 � � � � � � � � � � � � � � � � � � � � Hydro2 � � � � � � � � � � � � � � � � � � � � New Hydro Plants Hydro3 � � � � � � � � � � � � � � � � � � � � Hydro4 � � � � � � � � � � � � � � � � � � � � Hydro Total � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � Existing and Committed Thermal plants GTSM Small Gas Turbines 619 1,698 � � � � � � � � � � � � � � � � � � DSP Diesel Sapugaskanda 99,953 95,176 74,193 82,839 � � � � � � � � � � � � � � � � DSPX Diesel Sapugaskanda�Extension 97,637 97,637 97,614 97,625 97,628 83,868 41,593 33,420 27,693 25,271 25,140 23,761 23,793 11,877 11,796 6,980 � � � � GT7 Gas Turbine 7 2,832 6,329 1,220 3,988 25,904 232 216 239 313 � � � � � � � � � � � DLDL Lakdhanavi Diesel 32,114 21,454 9,699 14,445 � � � � � � � � � � � � � � � � DAPL Asia Power Diesel 76,971 74,783 62,412 67,173 72,865 30,757 10,495 7,517 6,750 � � � � � � � � � � � CCKP Kelanitissa Combined Cycle 20,737 30,443 8,200 23,151 80,387 5,253 1,921 2,255 2,245 3,448 3,520 5,051 6,629 2,129 11,277 9,396 4,992 7,257 10,420 7,750 CAES AES Combined Cycle 160,140 92,876 40,367 68,647 159,326 27,836 14,865 9,785 11,039 14,680 15,034 16,396 18,878 5,805 26,257 � � � � � DCPL Colombo Power Diesel 94,268 85,767 58,380 69,282 86,775 31,989 � � � � � � � � � � � � � � DHOR Horana Diesel 35,838 27,985 12,698 17,970 � � � � � � � � � � � � � � � � DMAT Matara Diesel 35,566 25,566 11,287 � � � � � � � � � � � � � � � � � DPUT Puttalam Diesel 140,908 139,805 125,101 132,547 136,975 68,767 � � � � � � � � � � � � � � DEMB Embilipitiya Diesel 154,658 127,538 69,395 95,247 136,276 41,596 � � � � � � � � � � � � � � GTKW Kerawalapitiya Gas Turbine 91,571 � � � � � � � � � � � � � � � � � � � CCKW Kerawalapitiya Combined Cycle � 393,972 384,971 389,800 391,980 274,204 93,979 75,686 70,528 67,418 66,780 64,415 70,834 26,498 74,574 38,523 20,126 26,540 36,996 26,234 CPUT Coal Puttalam � � 502,648 502,659 502,668 502,668 496,418 478,410 452,892 422,553 389,751 369,129 348,863 249,467 312,404 235,819 165,048 232,746 288,736 247,657 NCRE Existing and New RENW Renewables � � � � � � � � � � � � � � � � � � � � New Thermal Power Plants GT1 Gas turbine 1 � � � � � 92 96 119 164 774 1,012 1,565 2,374 865 4,167 4,182 2,369 3,895 4,369 3,304 GT2 Gas turbine 2 � � � � � � � � � � � � � � � � � � � � GT3 Gas turbine 3 � � � � � 1,138 515 564 723 1,250 1,531 2,221 3,184 1,120 10,111 9,142 4,974 8,030 15,916 12,022 CTRC Coal Trinco � � � � � � 1,388,963 2,079,319 2,757,941 3,421,404 4,063,969 4,703,200 5,319,743 4,938,748 5,091,990 4,659,899 4,116,211 4,445,925 4,687,988 4,309,178 CCHF CC�Heavy Fuel � � � � � � � � � � � � � � � � � � � � CCDL CC�Diesel � � � � � � � � � � � � � � � � � � � � CCLN CC�LNG � � � � � � � � � � � � � � � � � � � � COSB Coal�Subcritical � � � � � 1,542,685 1,227,374 1,072,820 940,682 835,365 747,651 705,921 676,224 413,028 607,844 411,814 269,080 564,427 969,571 793,994 COSP Coal�Supercritical � � � � � � � � � � � � � 1,391,281 1,391,277 2,782,510 4,164,234 4,169,463 4,171,956 5,547,138 PUMP Pumped Storage (generation) � � � � � � � � � � � � � � � � � � � � Total Fuel Use 1,043,813 1,221,028 1,458,185 1,565,372 1,690,783 2,611,085 3,276,436 3,760,133 4,270,970 4,792,162 5,314,387 5,891,659 6,470,522 7,040,818 7,541,697 8,158,265 8,747,032 9,458,282 10,185,951 10,947,275 Total themal generation exc. NCR 4,857 5,670 6,572 7,099 8,013 8,989 10,010 11,228 12,558 13,920 15,289 16,828 18,395 20,016 21,663 23,447 25,254 27,318 29,421 31,777 Spec. fuel consumpion (kg/kWh) 0.215 0.215 0.222 0.220 0.211 0.290 0.327 0.335 0.340 0.344 0.348 0.350 0.352 0.352 0.348 0.348 0.346 0.346 0.346 0.345 Sri Lanka: Environmental Issues in the Power Sector 189 ECA, RMA and ERM Detailed outputs from the model for the 15 cases Case 5: Fuel consumption in MT Case 5 LNG, Hydro and NCRE forced 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 Existing and Committed Hydro plants Hydro1 � � � � � � � � � � � � � � � � � � � � Hydro2 � � � � � � � � � � � � � � � � � � � � New Hydro Plants Hydro3 � � � � � � � � � � � � � � � � � � � � Hydro4 � � � � � � � � � � � � � � � � � � � � Hydro Total � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � Existing and Committed Thermal plants GTSM Small Gas Turbines 619 1,698 � � � � � � � � � � � � � � � � � � DSP Diesel Sapugaskanda 99,953 95,176 74,193 82,839 � � � � � � � � � � � � � � � � DSPX Diesel Sapugaskanda�Extension 97,637 97,637 97,614 97,625 97,628 59,461 30,479 47,851 37,205 29,813 23,635 21,529 20,404 19,190 9,960 4,846 � � � � GT7 Gas Turbine 7 2,832 6,329 1,220 3,988 25,904 14 10 160 234 � � � � � � � � � � � DLDL Lakdhanavi Diesel 32,114 21,454 9,699 14,445 � � � � � � � � � � � � � � � � DAPL Asia Power Diesel 76,971 74,783 62,412 67,173 72,865 9,499 3,693 14,791 10,150 � � � � � � � � � � � CCKP Kelanitissa Combined Cycle 20,737 30,443 8,200 23,151 80,387 156 128 4,215 2,307 3,108 2,825 2,949 3,196 3,837 5,234 4,402 6,407 9,407 12,971 20,621 CAES AES Combined Cycle 160,140 92,876 40,367 68,647 159,326 2,283 2,761 22,461 14,943 13,452 8,926 10,292 9,735 10,191 13,203 � � � � � DCPL Colombo Power Diesel 94,268 85,767 58,380 69,282 86,775 8,792 � � � � � � � � � � � � � � DHOR Horana Diesel 35,838 27,985 12,698 17,970 � � � � � � � � � � � � � � � � DMAT Matara Diesel 35,566 25,566 11,287 � � � � � � � � � � � � � � � � � DPUT Puttalam Diesel 140,908 139,805 125,101 132,547 136,975 25,654 � � � � � � � � � � � � � � DEMB Embilipitiya Diesel 154,658 127,538 69,395 95,247 136,276 7,396 � � � � � � � � � � � � � � GTKW Kerawalapitiya Gas Turbine 91,571 � � � � � � � � � � � � � � � � � � � CCKW Kerawalapitiya Combined Cycle � 393,972 384,971 389,800 391,980 136,796 54,004 131,386 98,955 73,716 63,596 53,247 50,544 46,900 56,971 21,589 28,996 38,483 48,990 64,759 CPUT Coal Puttalam � � 502,648 502,659 502,668 488,033 487,539 494,982 498,952 501,092 502,001 502,495 502,629 502,646 502,651 502,649 502,648 502,646 502,658 502,672 NCRE Existing and New RENW Renewables � � � � � � � � � � � � � � � � � � � � New Thermal Power Plants GT1 Gas turbine 1 � � � � 9,894 4 4 75 128 521 606 844 1,180 1,630 2,537 2,387 2,576 2,158 2,519 2,413 GT2 Gas turbine 2 � � � � � � � � � � � � � � � � � 1,632 1,852 1,752 GT3 Gas turbine 3 � � � � 40,473 35 33 575 514 832 921 1,193 1,546 2,050 2,935 2,704 6,949 13,907 23,742 44,855 CTRC Coal Trinco � � � � � 1,388,249 1,387,779 1,388,671 1,389,035 1,389,129 1,389,146 1,389,164 1,389,170 1,389,169 1,389,168 1,389,178 1,389,186 1,389,200 1,389,202 1,389,201 CCHF CC�Heavy Fuel � � � � � � � � � � � � � � � � � � � � CCDL CC�Diesel � � � � � � � � � � � � � � � � � � � � CCLN CC�LNG � � � � � � � � 187,164 381,473 575,577 792,969 1,016,351 1,249,752 1,483,498 1,782,420 2,039,621 2,328,677 2,620,621 2,936,834 COSB Coal�Subcritical � � � � � 634,645 1,047,254 1,253,968 1,366,235 1,447,967 1,499,576 1,536,303 1,557,916 1,570,320 1,576,699 1,580,277 1,582,416 1,583,740 1,584,185 1,584,328 COSP Coal�Supercritical � � � � � � � � � � � � � � � � � � � � PUMP Pumped Storage (generation) � � � � � � � � � � � � � � � � � � � � Total Fuel Use 1,043,813 1,221,028 1,458,185 1,565,372 1,741,150 2,761,016 3,013,684 3,359,134 3,605,820 3,841,102 4,066,809 4,310,985 4,552,670 4,795,687 5,042,858 5,290,452 5,558,798 5,869,849 6,186,740 6,547,436 Total themal generation exc. NCR 4,857 5,670 6,572 7,099 8,013 8,752 9,133 10,351 11,681 13,043 14,412 15,952 17,521 19,136 20,785 22,570 24,372 26,442 28,544 30,897 Spec. fuel consumpion (kg/kWh) 0.215 0.215 0.222 0.220 0.217 0.315 0.330 0.325 0.309 0.294 0.282 0.270 0.260 0.251 0.243 0.234 0.228 0.222 0.217 0.212 Sri Lanka: Environmental Issues in the Power Sector 190 ECA, RMA and ERM Detailed outputs from the model for the 15 cases Case 6: Fuel consumption in MT Case 6 Early Supercritical Coal 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 Existing and Committed Hydro plants Hydro1 � � � � � � � � � � � � � � � � � � � � Hydro2 � � � � � � � � � � � � � � � � � � � � New Hydro Plants Hydro3 � � � � � � � � � � � � � � � � � � � � Hydro4 � � � � � � � � � � � � � � � � � � � � Hydro Total � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � Existing and Committed Thermal plants GTSM Small Gas Turbines 686 2,245 � � � � � � � � � � � � � � � � � � DSP Diesel Sapugaskanda 99,963 96,116 79,677 88,222 � � � � � � � � � � � � � � � � DSPX Diesel Sapugaskanda�Extension 97,637 97,637 97,630 97,631 97,637 91,748 63,340 78,815 43,761 15,574 30,485 16,122 5,422 18,052 4,640 10,659 � � � � GT7 Gas Turbine 7 3,065 8,939 2,275 9,520 31,990 529 540 6,914 1,008 � � � � � � � � � � � DLDL Lakdhanavi Diesel 32,242 23,436 11,422 19,772 � � � � � � � � � � � � � � � � DAPL Asia Power Diesel 76,974 75,551 65,683 71,706 75,295 41,918 20,018 37,671 14,937 � � � � � � � � � � � CCKP Kelanitissa Combined Cycle 21,680 35,660 12,038 33,667 110,645 16,839 10,478 43,076 7,571 1,645 9,207 2,397 1,125 4,500 2,496 6,763 4,272 2,878 5,647 4,733 CAES AES Combined Cycle 162,589 103,325 49,257 86,672 189,903 58,568 39,800 85,101 25,406 5,284 27,052 7,135 2,564 12,165 5,383 � � � � � DCPL Colombo Power Diesel 94,394 87,732 67,712 78,662 91,238 45,115 � � � � � � � � � � � � � � DHOR Horana Diesel 35,989 29,424 15,594 24,038 � � � � � � � � � � � � � � � � DMAT Matara Diesel 35,805 28,252 13,586 � � � � � � � � � � � � � � � � � DPUT Puttalam Diesel 140,910 140,486 129,299 136,990 139,418 89,641 � � � � � � � � � � � � � � DEMB Embilipitiya Diesel 155,221 135,398 84,422 113,776 147,967 62,442 � � � � � � � � � � � � � � GTKW Kerawalapitiya Gas Turbine 94,104 � � � � � � � � � � � � � � � � � � � CCKW Kerawalapitiya Combined Cycle � 394,051 389,017 392,245 393,605 326,055 163,867 257,582 109,008 32,648 87,197 33,936 10,664 47,307 21,999 65,124 42,625 24,795 42,897 33,436 CPUT Coal Puttalam � � 502,658 502,664 502,664 502,664 501,753 502,493 475,280 380,770 421,995 324,211 221,578 296,302 206,775 287,704 214,957 163,660 226,083 196,834 NCRE Existing and New RENW Renewables � � � � � � � � � � � � � � � � � � � � New Thermal Power Plants GT1 Gas turbine 1 � � � 909 14,903 221 294 3,907 778 615 2,739 1,056 411 2,415 1,323 4,620 3,064 2,016 4,416 3,749 GT2 Gas turbine 2 � � � � 85,765 5,009 3,206 31,795 3,480 1,146 4,893 1,905 736 3,529 2,122 5,701 3,745 2,583 5,198 4,348 GT3 Gas turbine 3 � � � � � � � � � � � � � � � � � � � � CTRC Coal Trinco � � � � � � 1,389,180 1,389,187 1,383,190 1,273,162 1,320,123 1,139,759 916,045 1,048,151 875,110 984,119 831,091 674,666 843,723 722,748 CCHF CC�Heavy Fuel � � � � � � � � � � � � � � � � � � 63,718 53,976 CCDL CC�Diesel � � � � � � � � � � � � � � � 30,397 16,763 10,605 20,214 15,631 CCLN CC�LNG � � � � � � � � � � � � � � � � � � � � COSB Coal�Subcritical � � � � � 1,570,207 1,399,455 1,484,653 1,138,910 670,958 923,928 566,075 311,469 533,271 326,682 536,263 386,770 283,281 467,214 400,599 COSP Coal�Supercritical � � � � � � � � 1,391,293 2,778,137 2,781,158 4,120,903 5,351,761 5,428,049 6,604,431 6,713,136 7,853,425 8,946,066 9,137,304 10,249,801 PUMP Pumped Storage (generation) � � � � � � � � � � � � � � � � � � � � Total Fuel Use 1,051,259 1,258,252 1,520,269 1,656,474 1,881,030 2,810,954 3,591,931 3,921,194 4,594,623 5,159,938 5,608,777 6,213,499 6,821,775 7,393,739 8,050,961 8,644,486 9,356,712 10,110,550 10,816,413 11,685,853 Total themal generation exc. NCRE 4,893 5,850 6,861 7,531 8,662 9,892 11,166 12,562 14,038 15,510 17,019 18,672 20,423 22,252 24,124 26,082 28,107 30,322 32,599 35,170 Spec. fuel consumpion (kg/kWh) 0.215 0.215 0.222 0.220 0.217 0.284 0.322 0.312 0.327 0.333 0.330 0.333 0.334 0.332 0.334 0.331 0.333 0.333 0.332 0.332 Sri Lanka: Environmental Issues in the Power Sector 191 ECA, RMA and ERM Detailed outputs from the model for the 15 cases Case 7: Fuel consumption in MT Case 7 No coal beyond Trinco Commitments 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 Existing and Committed Hydro plants Hydro1 � � � � � � � � � � � � � � � � � � � � Hydro2 � � � � � � � � � � � � � � � � � � � � New Hydro Plants Hydro3 � � � � � � � � � � � � � � � � � � � � Hydro4 � � � � � � � � � � � � � � � � � � � � Hydro Total � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � Existing and Committed Thermal plants GTSM Small Gas Turbines 686 2,245 � � � � � � � � � � � � � � � � � � DSP Diesel Sapugaskanda 99,963 96,116 79,677 88,222 � � � � � � � � � � � � � � � � DSPX Diesel Sapugaskanda�Extension 97,637 97,637 97,630 97,631 97,637 67,048 25,468 49,203 39,579 32,150 29,213 27,280 26,628 26,747 13,506 9,307 � � � � GT7 Gas Turbine 7 3,065 8,939 2,275 9,520 68,289 224 263 3,006 2,298 � � � � � � � � � � � DLDL Lakdhanavi Diesel 32,242 23,436 11,422 19,772 � � � � � � � � � � � � � � � � DAPL Asia Power Diesel 76,974 75,551 65,683 71,706 75,284 16,018 4,004 14,786 13,074 � � � � � � � � � � � CCKP Kelanitissa Combined Cycle 21,680 35,660 12,038 33,667 110,384 934 962 8,492 6,477 9,383 8,631 9,020 11,046 12,894 18,438 15,919 23,751 12,304 18,092 15,665 CAES AES Combined Cycle 162,589 103,325 49,257 86,672 189,669 8,739 4,258 27,654 22,181 27,071 24,852 24,991 27,456 31,098 36,200 � � � � � DCPL Colombo Power Diesel 94,394 87,732 67,712 78,662 91,246 13,930 � � � � � � � � � � � � � � DHOR Horana Diesel 35,989 29,424 15,594 24,038 � � � � � � � � � � � � � � � � DMAT Matara Diesel 35,805 28,252 13,586 � � � � � � � � � � � � � � � � � DPUT Puttalam Diesel 140,910 140,486 129,299 136,990 139,434 39,072 � � � � � � � � � � � � � � DEMB Embilipitiya Diesel 155,221 135,398 84,422 113,776 148,006 16,055 � � � � � � � � � � � � � � GTKW Kerawalapitiya Gas Turbine 94,104 � � � � � � � � � � � � � � � � � � � CCKW Kerawalapitiya Combined Cycle � 394,051 389,017 392,245 393,599 188,856 49,041 127,263 108,751 93,259 84,960 85,236 84,535 84,023 93,284 58,088 67,561 44,535 56,773 49,691 CPUT Coal Puttalam � � 502,658 502,664 502,664 502,664 501,650 502,452 502,604 502,656 502,663 502,664 502,664 502,664 502,664 502,664 502,664 502,664 502,664 502,664 NCRE Existing and New RENW Renewables � � � � � � � � � � � � � � � � � � � � New Thermal Power Plants GT1 Gas turbine 1 � � � 909 64,493 123 159 1,609 2,039 6,609 7,195 8,781 7,476 6,758 7,211 7,412 8,620 5,365 7,392 7,276 GT2 Gas turbine 2 � � � � � � � � � � � � � � � � � � 2,996 2,911 GT3 Gas turbine 3 � � � � � � � � � � � � 5,224 11,635 21,739 20,494 36,453 22,454 33,778 31,701 CTRC Coal Trinco � � � � � � 1,389,180 1,389,187 1,389,186 1,389,187 1,389,187 1,389,187 1,389,187 1,389,187 1,389,187 1,389,186 1,389,187 1,389,187 1,389,187 1,389,187 CCHF CC�Heavy Fuel � � � � � � � � � � � � � � � � � � � 67,903 CCDL CC�Diesel � � � � � � � � � � � � � � � � � � � � CCLN CC�LNG � � � � � 269,291 163,449 223,695 444,995 665,135 889,729 1,127,413 1,377,242 1,637,849 1,899,564 2,245,903 2,525,572 2,884,213 3,196,427 3,532,844 COSB Coal�Subcritical � � � � � 1,568,792 1,372,075 1,473,407 1,526,008 1,554,106 1,570,449 1,578,584 1,582,463 1,583,904 1,584,304 1,584,390 1,584,398 1,584,397 1,584,397 1,584,397 COSP Coal�Supercritical � � � � � � � � � � � � � � � � � � � � PUMP Pumped Storage (generation) � � � � � � � � � � � � � � � � � � � � Total Fuel Use 1,051,259 1,258,252 1,520,269 1,656,474 1,880,705 2,691,745 3,510,509 3,820,754 4,057,193 4,279,556 4,506,880 4,753,155 5,013,921 5,286,758 5,566,096 5,833,362 6,138,205 6,445,119 6,791,706 7,184,239 Total themal generation exc. NCRE 4,893 5,850 6,861 7,531 8,662 9,892 11,166 12,564 14,039 15,508 17,020 18,667 20,418 22,252 24,120 26,086 28,103 30,320 32,602 35,171 Spec. fuel consumpion (kg/kWh) 0.215 0.215 0.222 0.220 0.217 0.272 0.314 0.304 0.289 0.276 0.265 0.255 0.246 0.238 0.231 0.224 0.218 0.213 0.208 0.204 Sri Lanka: Environmental Issues in the Power Sector 192 ECA, RMA and ERM Detailed outputs from the model for the 15 cases Case 8: Fuel consumption in MT Case 8 Pumped storage plants allowed 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 Existing and Committed Hydro plants Hydro1 � � � � � � � � � � � � � � � � � � � � Hydro2 � � � � � � � � � � � � � � � � � � � � New Hydro Plants Hydro3 � � � � � � � � � � � � � � � � � � � � Hydro4 � � � � � � � � � � � � � � � � � � � � Hydro Total � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � Existing and Committed Thermal plants GTSM Small Gas Turbines 686 2,055 � � � � � � � � � � � � � � � � � � DSP Diesel Sapugaskanda 99,963 96,116 79,763 88,221 � � � � � � � � � � � � � � � � DSPX Diesel Sapugaskanda�Extension 97,637 97,637 97,630 97,631 97,637 91,783 63,371 22,769 22,668 21,565 22,936 23,203 9,680 23,046 6,648 3,347 � � � � GT7 Gas Turbine 7 2,755 7,529 1,921 9,405 21,207 271 334 51 96 � � � � � � � � � � � DLDL Lakdhanavi Diesel 32,242 23,744 12,432 19,712 � � � � � � � � � � � � � � � � DAPL Asia Power Diesel 76,974 75,551 65,648 71,694 75,287 42,740 18,631 3,576 4,913 � � � � � � � � � � � CCKP Kelanitissa Combined Cycle 21,161 36,058 11,212 33,597 110,706 16,266 10,572 1,210 1,395 2,325 3,438 4,819 1,579 8,357 4,071 4,184 7,294 4,260 8,735 6,024 CAES AES Combined Cycle 162,589 103,619 48,158 86,710 189,087 57,857 39,124 5,967 6,854 10,431 10,854 14,807 4,535 19,234 9,396 � � � � � DCPL Colombo Power Diesel 94,394 87,774 68,282 78,662 91,128 43,728 � � � � � � � � � � � � � � DHOR Horana Diesel 35,989 29,338 15,594 24,062 � � � � � � � � � � � � � � � � DMAT Matara Diesel 35,805 28,461 14,151 � � � � � � � � � � � � � � � � � DPUT Puttalam Diesel 140,910 140,486 129,374 137,002 139,388 91,590 � � � � � � � � � � � � � � DEMB Embilipitiya Diesel 155,221 135,449 84,997 113,960 148,896 62,387 � � � � � � � � � � � � � � GTKW Kerawalapitiya Gas Turbine 95,103 � � � � � � � � � � � � � � � � � � � CCKW Kerawalapitiya Combined Cycle � 394,051 389,017 392,245 393,602 325,838 165,218 57,316 59,227 61,263 55,896 57,751 18,741 64,138 30,953 17,191 30,068 29,164 40,424 41,212 CPUT Coal Puttalam � � 502,658 502,664 502,664 502,664 501,753 466,302 438,839 411,232 388,172 367,620 275,924 337,651 262,828 187,553 263,434 204,288 274,497 240,452 NCRE Existing and New RENW Renewables � � � � � � � � � � � � � � � � � � � � New Thermal Power Plants GT1 Gas turbine 1 � � � 909 5,825 99 140 15 32 209 330 634 254 1,846 1,022 1,188 2,445 1,628 3,455 2,835 GT2 Gas turbine 2 � � � � � � � � � � � � � � � � � � � � GT3 Gas turbine 3 � � � � 105,968 5,772 3,474 453 695 1,429 2,034 3,243 1,263 7,520 3,763 4,160 6,923 4,402 7,814 6,214 CTRC Coal Trinco � � � � � � 1,389,180 2,768,439 3,442,802 4,104,309 4,756,038 5,393,016 5,068,254 5,221,834 4,864,124 4,393,776 4,800,907 4,309,693 4,834,124 4,400,013 CCHF CC�Heavy Fuel � � � � � � � � � � � � � � � � � � � � CCDL CC�Diesel � � � � � � � � � � � � � � � � � � � � CCLN CC�LNG � � � � � � � � � � � � � � � � � � � � COSB Coal�Subcritical � � � � � 1,570,207 1,400,591 961,098 864,718 783,917 727,650 712,762 413,040 679,228 429,972 257,354 479,346 342,093 574,688 463,159 COSP Coal�Supercritical � � � � � � � � � � � � 1,391,293 1,391,293 2,782,587 4,172,071 4,173,887 5,563,068 5,565,176 6,954,630 PUMP Pumped Storage (generation) � � � � � � � � � � � � � � � � � � � � Total Fuel Use 1,051,428 1,257,869 1,520,838 1,656,473 1,881,395 2,811,202 3,592,389 4,287,197 4,842,240 5,396,679 5,967,348 6,577,855 7,184,564 7,754,146 8,395,363 9,040,824 9,764,304 10,458,594 11,308,912 12,114,540 Total themal generation exc. NCRE 4,893 5,850 6,861 7,531 8,661 9,892 11,166 12,565 14,039 15,511 17,024 18,672 20,423 22,250 24,123 26,088 28,438 30,493 33,375 35,758 Spec. fuel consumpion (kg/kWh) 0.215 0.215 0.222 0.220 0.217 0.284 0.322 0.341 0.345 0.348 0.351 0.352 0.352 0.349 0.348 0.347 0.343 0.343 0.339 0.339 Sri Lanka: Environmental Issues in the Power Sector 193 ECA, RMA and ERM Detailed outputs from the model for the 15 cases Case 9: Fuel consumption in MT Case 9 DSM intervention 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 Existing and Committed Hydro plants Hydro1 Hydro2 New Hydro Plants Hydro3 Hydro4 Hydro Total Existing and Committed Thermal plants GTSM Small Gas Turbines 752 1,816 � � � � � � � � � � � � � � � � � � DSP Diesel Sapugaskanda 99,962 95,253 75,581 83,879 � � � � � � � � � � � � � � � � DSPX Diesel Sapugaskanda�Extension 97,637 97,637 97,567 97,620 97,623 88,022 55,503 17,726 17,233 17,004 17,608 19,263 35,659 22,854 5,422 12,864 � � � � GT7 Gas Turbine 7 3,260 7,451 1,224 4,596 11,271 24 36 6 7 � � � � � � � � � � � DLDL Lakdhanavi Diesel 32,297 22,666 9,905 15,879 � � � � � � � � � � � � � � � � DAPL Asia Power Diesel 76,974 75,126 62,807 68,146 73,491 35,968 13,141 1,537 1,605 � � � � � � � � � � � CCKP Kelanitissa Combined Cycle 22,548 32,957 8,651 26,724 89,028 6,519 2,808 111 185 392 841 1,217 14,234 3,163 1,398 24,455 11,616 5,275 3,511 20,019 CAES AES Combined Cycle 164,369 98,653 40,483 70,824 170,358 37,663 25,681 1,695 2,039 2,985 3,890 6,635 39,672 11,839 4,171 � � � � � DCPL Colombo Power Diesel 94,485 86,447 63,761 72,628 87,999 39,157 � � � � � � � � � � � � � � DHOR Horana Diesel 36,154 28,591 13,519 19,865 � � � � � � � � � � � � � � � � DMAT Matara Diesel 35,884 27,442 11,992 � � � � � � � � � � � � � � � � � DPUT Puttalam Diesel 140,910 140,168 124,865 133,690 137,384 80,112 � � � � � � � � � � � � � � DEMB Embilipitiya Diesel 155,465 132,292 77,047 102,375 141,247 51,965 � � � � � � � � � � � � � � GTKW Kerawalapitiya Gas Turbine 96,161 � � � � � � � � � � � � � � � � � � � CCKW Kerawalapitiya Combined Cycle � 393,963 383,556 389,358 392,251 304,215 132,928 32,882 39,187 42,769 41,512 45,051 109,401 57,360 21,145 76,595 49,837 26,113 14,477 63,859 CPUT Coal Puttalam � � 502,640 502,645 502,663 502,663 499,769 448,924 418,737 389,917 369,941 349,782 391,850 322,333 239,533 305,149 242,003 191,485 147,835 218,330 NCRE Existing and New RENW Renewables � � � � � � � � � � � � � � � � � � � � New Thermal Power Plants GT1 Gas turbine 1 � � � � � � � � � � � � 447 199 112 1,172 740 445 302 1,037 GT2 Gas turbine 2 � � � � � � � � � � � � � � � � � � � � GT3 Gas turbine 3 � � � � 71,159 1,604 354 49 77 174 303 553 8,223 2,218 1,173 25,262 13,065 7,745 5,356 35,142 CTRC Coal Trinco � � � � � � 1,389,134 2,758,252 3,423,658 4,073,173 4,715,987 5,342,643 5,425,468 5,158,600 4,765,701 4,977,638 4,583,077 4,123,132 3,700,033 4,101,724 CCHF CC�Heavy Fuel � � � � � � � � � � � � � � � � � � � � CCDL CC�Diesel � � � � � � � � � � � � � � � � � � � � CCLN CC�LNG � � � � � � � � � � � � � � � � � � � � COSB Coal�Subcritical � � � � � 1,556,160 1,337,142 859,148 779,312 705,319 663,850 644,674 888,250 624,873 399,097 623,302 459,008 333,924 237,790 440,434 COSP Coal�Supercritical � � � � � � � � � � � � � 1,391,293 2,782,597 2,782,587 4,172,527 5,547,331 6,882,464 6,916,713 PUMP Pumped Storage (generation) � � � � � � � � � � � � � � � � � � � � Total Fuel Use 1,056,860 1,240,462 1,473,599 1,588,228 1,774,472 2,704,074 3,456,498 4,120,331 4,682,039 5,231,733 5,813,932 6,409,818 6,913,205 7,594,731 8,220,348 8,829,024 9,531,873 10,235,450 10,991,768 11,797,259 Total themal generation exc. NCRE 4,921 5,764 6,640 7,207 8,177 9,400 10,643 12,009 13,500 14,957 16,511 18,118 19,848 21,737 23,563 25,522 27,593 29,740 32,070 34,550 Spec. fuel consumpion (kg/kWh) 0.215 0.215 0.222 0.220 0.217 0.288 0.325 0.343 0.347 0.350 0.352 0.354 0.348 0.349 0.349 0.346 0.345 0.344 0.343 0.341 Sri Lanka: Environmental Issues in the Power Sector 194 ECA, RMA and ERM Detailed outputs from the model for the 15 cases Case 10: Fuel consumption in MT Case 10 High demand forecast 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 Existing and Committed Hydro plants Hydro1 � � � � � � � � � � � � � � � � � � � � Hydro2 � � � � � � � � � � � � � � � � � � � � New Hydro Plants Hydro3 � � � � � � � � � � � � � � � � � � � � Hydro4 � � � � � � � � � � � � � � � � � � � � Hydro Total � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � Existing and Committed Thermal plants GTSM Small Gas Turbines 686 4,263 � � � � � � � � � � � � � � � � � � DSP Diesel Sapugaskanda 99,963 96,989 87,116 37,303 � � � � � � � � � � � � � � � � DSPX Diesel Sapugaskanda�Extension 97,637 97,637 97,630 97,637 97,637 64,597 39,721 38,792 35,504 21,476 37,365 52,797 36,434 26,431 9,634 6,684 � � � � GT7 Gas Turbine 7 3,065 14,809 2,540 105 3,307 3 6 14 41 � � � � � � � � � � � DLDL Lakdhanavi Diesel 32,242 26,478 17,912 5,522 � � � � � � � � � � � � � � � � DAPL Asia Power Diesel 76,974 76,468 71,464 36,924 60,391 1,012 465 722 1,263 � � � � � � � � � � � CCKP Kelanitissa Combined Cycle 21,680 46,019 28,297 1,642 45,645 86 162 284 559 249 2,125 12,606 5,770 3,076 2,104 2,774 2,176 9,392 8,005 8,090 CAES AES Combined Cycle 162,589 121,308 76,610 19,239 96,369 437 689 1,120 1,973 959 6,055 29,369 13,724 6,988 4,685 � � � � � DCPL Colombo Power Diesel 94,394 89,771 76,325 30,614 67,904 764 � � � � � � � � � � � � � � DHOR Horana Diesel 35,989 31,898 23,007 6,383 � � � � � � � � � � � � � � � � DMAT Matara Diesel 35,805 30,053 20,733 � � � � � � � � � � � � � � � � � DPUT Puttalam Diesel 140,910 140,619 136,084 87,767 119,833 4,099 � � � � � � � � � � � � � � DEMB Embilipitiya Diesel 155,221 141,391 112,313 35,692 100,167 777 � � � � � � � � � � � � � � GTKW Kerawalapitiya Gas Turbine 94,104 � � � � � � � � � � � � � � � � � � � CCKW Kerawalapitiya Combined Cycle � 394,077 391,610 330,385 369,589 48,465 9,456 11,305 17,799 5,228 29,476 81,657 45,466 26,631 15,771 10,388 8,145 30,038 24,489 23,862 CPUT Coal Puttalam � � 502,664 502,664 502,664 502,113 472,506 452,657 434,868 352,061 400,621 433,849 371,494 315,918 259,144 209,879 159,894 228,516 197,487 177,271 NCRE Existing and New RENW Renewables � � � � � � � � � � � � � � � � � � � � New Thermal Power Plants GT1 Gas turbine 1 � � � � � � � � � � � 1,169 616 354 245 385 314 2,465 2,169 2,352 GT2 Gas turbine 2 � � � � � � � � � � � � � � � � � � � � GT3 Gas turbine 3 � � 10,807 302 39,149 41 64 143 325 154 1,599 13,322 6,628 3,787 2,657 3,693 2,988 17,921 15,547 16,139 CTRC Coal Trinco � � � � � 1,389,187 2,773,551 3,456,209 4,131,028 5,383,485 5,455,903 5,505,241 5,331,371 5,050,123 4,667,213 4,238,264 3,808,886 4,208,733 3,868,970 3,600,300 CCHF CC�Heavy Fuel � � � 687,841 697,631 312,391 153,670 158,510 162,876 72,641 168,450 273,738 182,629 120,719 85,642 59,553 44,421 118,135 96,952 88,395 CCDL CC�Diesel � � � � � � � � � � � � � � � � � � � � CCLN CC�LNG � � � � � � � � � � � � � � � � � � � � COSB Coal�Subcritical � � � � � 1,413,090 1,036,374 975,830 941,575 653,816 888,669 1,089,467 872,979 661,534 504,625 380,838 295,385 480,058 412,516 374,252 COSP Coal�Supercritical � � � � � � � � � � � � 1,391,293 2,782,587 4,173,492 5,554,934 6,904,657 6,930,200 8,265,372 9,565,962 PUMP Pumped Storage (generation) � � � � � � � � � � � � � � � � � � � � Total Fuel Use 1,051,259 1,311,778 1,655,108 1,880,021 2,200,287 3,737,061 4,486,665 5,095,585 5,727,811 6,490,069 6,990,262 7,493,213 8,258,405 8,998,148 9,725,211 10,467,393 11,226,865 12,025,458 12,891,507 13,856,624 Total themal generation exc. NCRE 4,893 6,112 7,498 8,644 10,197 11,829 13,356 14,994 16,703 18,401 20,134 22,011 24,019 26,116 28,253 30,498 32,808 35,324 37,941 40,876 Spec. fuel consumpion (kg/kWh) 0.215 0.215 0.221 0.218 0.216 0.316 0.336 0.340 0.343 0.353 0.347 0.340 0.344 0.345 0.344 0.343 0.342 0.340 0.340 0.339 Sri Lanka: Environmental Issues in the Power Sector 195 ECA, RMA and ERM Detailed outputs from the model for the 15 cases Case 11: Fuel consumption in MT Case 11 High fuel prices 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 Existing and Committed Hydro plants Hydro1 � � � � � � � � � � � � � � � � � � � � Hydro2 � � � � � � � � � � � � � � � � � � � � New Hydro Plants Hydro3 � � � � � � � � � � � � � � � � � � � � Hydro4 � � � � � � � � � � � � � � � � � � � � Hydro Total � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � Existing and Committed Thermal plants GTSM Small Gas Turbines 686 2,245 � � � � � � � � � � � � � � � � � � DSP Diesel Sapugaskanda 99,963 96,116 79,677 88,222 � � � � � � � � � � � � � � � � DSPX Diesel Sapugaskanda�Extension 97,637 97,637 97,630 97,631 97,637 91,780 62,295 24,547 24,071 23,151 23,307 23,228 10,652 24,318 7,297 3,517 � � � � GT7 Gas Turbine 7 3,065 8,939 2,275 9,520 21,565 271 334 51 96 � � � � � � � � � � � DLDL Lakdhanavi Diesel 32,242 23,436 11,422 19,772 � � � � � � � � � � � � � � � � DAPL Asia Power Diesel 76,974 75,551 65,683 71,706 75,287 41,906 19,462 4,150 5,140 � � � � � � � � � � � CCKP Kelanitissa Combined Cycle 21,680 35,660 12,038 33,667 110,277 16,990 10,939 1,233 1,395 2,325 3,594 5,298 1,579 8,974 4,071 4,184 6,875 4,318 7,072 5,807 CAES AES Combined Cycle 162,589 103,325 49,257 86,672 188,643 58,259 39,973 6,233 7,438 11,889 11,934 15,957 4,535 23,352 10,031 � � � � � DCPL Colombo Power Diesel 94,394 87,732 67,712 78,662 91,125 44,190 � � � � � � � � � � � � � � DHOR Horana Diesel 35,989 29,424 15,594 24,038 � � � � � � � � � � � � � � � � DMAT Matara Diesel 35,805 28,252 13,586 � � � � � � � � � � � � � � � � � DPUT Puttalam Diesel 140,910 140,486 129,299 136,990 139,388 91,379 � � � � � � � � � � � � � � DEMB Embilipitiya Diesel 155,221 135,398 84,422 113,776 148,885 62,088 � � � � � � � � � � � � � � GTKW Kerawalapitiya Gas Turbine 94,104 � � � � � � � � � � � � � � � � � � � CCKW Kerawalapitiya Combined Cycle � 394,051 389,017 392,245 393,602 325,276 164,729 59,322 61,740 63,551 60,337 64,719 22,402 71,797 39,138 18,139 26,784 16,301 25,090 19,230 CPUT Coal Puttalam � � 502,658 502,664 502,664 502,664 501,753 466,295 438,695 410,098 387,603 366,826 266,945 335,135 251,621 180,189 252,871 199,462 264,222 228,260 NCRE Existing and New RENW Renewables � � � � � � � � � � � � � � � � � � � � New Thermal Power Plants GT1 Gas turbine 1 � � � 909 5,873 99 140 15 32 209 330 634 254 1,846 1,022 1,188 2,570 1,702 4,071 3,454 GT2 Gas turbine 2 � � � � � � � � � � � � � � � � � � � � GT3 Gas turbine 3 � � � � 106,942 5,772 3,480 453 695 1,429 2,034 3,243 1,263 7,520 3,763 4,160 7,121 4,579 8,003 6,631 CTRC Coal Trinco � � � � � � 1,389,180 2,768,439 3,442,802 4,104,309 4,756,038 5,392,960 5,064,644 5,221,577 4,856,223 4,370,248 4,662,670 4,230,199 4,539,391 4,181,119 CCHF CC�Heavy Fuel � � � � � � � � � � � � � � � � � � � � CCDL CC�Diesel � � � � � � � � � � � � � � � � � � � � CCLN CC�LNG � � � � � � � � � � � � � � � � � � � � COSB Coal�Subcritical � � � � � 1,570,207 1,399,455 953,124 856,700 776,093 717,842 698,854 422,913 658,535 439,256 290,587 603,809 441,515 834,250 702,226 COSP Coal�Supercritical � � � � � � � � � � � � 1,391,293 1,391,293 2,782,587 4,172,071 4,173,362 5,553,814 5,560,303 6,928,205 PUMP Pumped Storage (generation) � � � � � � � � � � � � � � � � � � � � Total Fuel Use 1,051,259 1,258,252 1,520,269 1,656,474 1,881,887 2,810,880 3,591,741 4,283,863 4,838,804 5,393,053 5,963,021 6,571,719 7,186,481 7,744,348 8,395,009 9,044,283 9,736,062 10,451,889 11,242,401 12,074,932 Total themal generation exc. NCRE 4,893 5,850 6,861 7,531 8,661 9,892 11,166 12,565 14,039 15,511 17,024 18,672 20,423 22,250 24,123 26,088 28,103 30,319 32,601 35,172 Spec. fuel consumpion (kg/kWh) 0.215 0.215 0.222 0.220 0.217 0.284 0.322 0.341 0.345 0.348 0.350 0.352 0.352 0.348 0.348 0.347 0.346 0.345 0.345 0.343 Sri Lanka: Environmental Issues in the Power Sector 196 ECA, RMA and ERM Detailed outputs from the model for the 15 cases Case 12: Fuel consumption in MT Case 12 Escalating fuel prices 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 Existing and Committed Hydro plants Hydro1 � � � � � � � � � � � � � � � � � � � � Hydro2 � � � � � � � � � � � � � � � � � � � � New Hydro Plants Hydro3 � � � � � � � � � � � � � � � � � � � � Hydro4 � � � � � � � � � � � � � � � � � � � � Hydro Total � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � Existing and Committed Thermal plants GTSM Small Gas Turbines 686 2,245 � � � � � � � � � � � � � � � � � � DSP Diesel Sapugaskanda 99,963 96,116 79,677 88,222 � � � � � � � � � � � � � � � � DSPX Diesel Sapugaskanda�Extension 97,637 97,637 97,630 97,631 97,637 91,780 62,295 24,547 24,071 23,151 23,307 23,228 10,652 24,318 7,297 3,517 � � � � GT7 Gas Turbine 7 3,065 8,939 2,275 9,520 21,565 271 334 51 96 � � � � � � � � � � � DLDL Lakdhanavi Diesel 32,242 23,436 11,422 19,772 � � � � � � � � � � � � � � � � DAPL Asia Power Diesel 76,974 75,551 65,683 71,706 75,287 41,906 19,462 4,150 5,140 � � � � � � � � � � � CCKP Kelanitissa Combined Cycle 21,680 35,660 12,038 33,667 110,277 16,990 10,939 1,233 1,395 2,325 3,594 5,298 1,579 8,974 4,071 4,184 2,647 11,319 7,458 6,214 CAES AES Combined Cycle 162,589 103,325 49,257 86,672 188,643 58,259 39,973 6,233 7,438 11,889 11,934 15,957 4,535 23,352 10,031 � � � � � DCPL Colombo Power Diesel 94,394 87,732 67,712 78,662 91,125 44,190 � � � � � � � � � � � � � � DHOR Horana Diesel 35,989 29,424 15,594 24,038 � � � � � � � � � � � � � � � � DMAT Matara Diesel 35,805 28,252 13,586 � � � � � � � � � � � � � � � � � DPUT Puttalam Diesel 140,910 140,486 129,299 136,990 139,388 91,379 � � � � � � � � � � � � � � DEMB Embilipitiya Diesel 155,221 135,398 84,422 113,776 148,885 62,088 � � � � � � � � � � � � � � GTKW Kerawalapitiya Gas Turbine 94,104 � � � � � � � � � � � � � � � � � � � CCKW Kerawalapitiya Combined Cycle � 394,051 389,017 392,245 393,602 325,276 164,729 59,322 61,740 63,551 60,337 64,719 22,402 71,797 39,138 18,139 10,375 41,564 26,621 20,157 CPUT Coal Puttalam � � 502,658 502,664 502,664 502,664 501,753 466,295 438,695 410,098 387,603 366,826 266,945 335,135 251,621 180,189 130,813 199,714 153,662 129,992 NCRE Existing and New RENW Renewables � � � � � � � � � � � � � � � � � � � � New Thermal Power Plants GT1 Gas turbine 1 � � � 909 5,873 99 140 15 32 209 330 634 254 1,846 1,022 1,188 768 2,560 1,806 1,563 GT2 Gas turbine 2 � � � � � � � � � � � � � � � � � 1,893 1,330 1,138 GT3 Gas turbine 3 � � � � 106,942 5,772 3,480 453 695 1,429 2,034 3,243 1,263 7,520 3,763 4,160 2,706 16,171 11,201 9,318 CTRC Coal Trinco � � � � � � 1,389,180 2,768,439 3,442,802 4,104,309 4,756,038 5,392,960 5,064,644 5,221,577 4,856,223 4,370,248 3,817,042 4,227,066 3,792,124 3,404,133 CCHF CC�Heavy Fuel � � � � � � � � � � � � � � � � � � � � CCDL CC�Diesel � � � � � � � � � � � � � � � � � � � � CCLN CC�LNG � � � � � � � � � � � � � � � � � � � � COSB Coal�Subcritical � � � � � 1,570,207 1,399,455 953,124 856,700 776,093 717,842 698,854 422,913 658,535 439,256 290,587 181,724 366,032 272,582 228,195 COSP Coal�Supercritical � � � � � � � � � � � � 1,391,293 1,391,293 2,782,587 4,172,071 5,540,780 5,553,814 6,900,631 8,199,633 PUMP Pumped Storage (generation) � � � � � � � � � � � � � � � � � � � � Total Fuel Use 1,051,259 1,258,252 1,520,269 1,656,474 1,881,887 2,810,880 3,591,741 4,283,863 4,838,804 5,393,053 5,963,021 6,571,719 7,186,481 7,744,348 8,395,009 9,044,283 9,686,856 10,420,131 11,167,415 12,000,342 Total themal generation exc. NCRE 4,893 5,850 6,861 7,531 8,661 9,892 11,166 12,565 14,039 15,511 17,024 18,672 20,423 22,250 24,123 26,088 28,110 30,315 32,604 35,175 Spec. fuel consumpion (kg/kWh) 0.215 0.215 0.222 0.220 0.217 0.284 0.322 0.341 0.345 0.348 0.350 0.352 0.352 0.348 0.348 0.347 0.345 0.344 0.343 0.341 Sri Lanka: Environmental Issues in the Power Sector 197 ECA, RMA and ERM Detailed outputs from the model for the 15 cases Case 13: Fuel consumption in MT Case 13 Lower discount rate 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 Existing and Committed Hydro plants Hydro1 � � � � � � � � � � � � � � � � � � � � Hydro2 � � � � � � � � � � � � � � � � � � � � New Hydro Plants Hydro3 � � � � � � � � � � � � � � � � � � � � Hydro4 � � � � � � � � � � � � � � � � � � � � Hydro Total � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � Existing and Committed Thermal plants GTSM Small Gas Turbines 686 2,245 � � � � � � � � � � � � � � � � � � DSP Diesel Sapugaskanda 99,963 96,116 79,677 88,311 � � � � � � � � � � � � � � � � DSPX Diesel Sapugaskanda�Extension 97,637 97,637 97,630 97,631 97,637 90,050 55,044 18,715 19,016 18,790 19,976 20,502 7,794 21,895 5,508 2,377 � � � � GT7 Gas Turbine 7 3,065 8,939 2,275 1,880 21,565 145 117 11 25 � � � � � � � � � � � DLDL Lakdhanavi Diesel 32,242 23,436 11,422 20,126 � � � � � � � � � � � � � � � � DAPL Asia Power Diesel 76,974 75,551 65,683 72,055 75,287 37,726 15,275 2,995 2,830 � � � � � � � � � � � CCKP Kelanitissa Combined Cycle 21,680 35,660 12,038 31,736 110,277 13,385 4,732 341 523 1,033 1,451 2,262 849 5,265 2,398 2,609 1,669 7,784 5,189 4,350 CAES AES Combined Cycle 162,589 103,325 49,257 88,073 188,643 48,800 28,946 3,168 3,022 5,467 6,674 8,726 2,370 15,409 6,061 � � � � � DCPL Colombo Power Diesel 94,394 87,732 67,712 78,637 91,125 41,473 � � � � � � � � � � � � � � DHOR Horana Diesel 35,989 29,424 15,594 24,346 � � � � � � � � � � � � � � � � DMAT Matara Diesel 35,805 28,252 13,586 � � � � � � � � � � � � � � � � � DPUT Puttalam Diesel 140,910 140,486 129,299 136,538 139,388 85,108 � � � � � � � � � � � � � � DEMB Embilipitiya Diesel 155,221 135,398 84,422 114,363 148,885 56,069 � � � � � � � � � � � � � � GTKW Kerawalapitiya Gas Turbine 94,104 � � � � � � � � � � � � � � � � � � � CCKW Kerawalapitiya Combined Cycle � 394,051 389,017 392,260 393,602 314,735 136,106 41,619 43,544 44,597 42,973 52,445 12,852 59,988 26,639 11,063 6,769 30,423 19,107 14,736 CPUT Coal Puttalam � � 502,658 502,664 502,664 502,664 500,804 453,574 425,298 396,043 371,078 351,994 251,767 319,692 238,014 169,943 122,860 190,850 145,763 122,393 NCRE Existing and New RENW Renewables � � � � � � � � � � � � � � � � � � � � New Thermal Power Plants GT1 Gas turbine 1 � � � � 5,873 43 37 5 5 87 124 247 128 1,029 575 709 424 1,712 1,210 1,056 GT2 Gas turbine 2 � � � � � � � � � � � � � � � � � � � � GT3 Gas turbine 3 � � � 9,641 106,942 3,820 1,347 162 262 559 868 1,528 609 4,163 2,236 2,572 1,682 10,683 7,389 6,253 CTRC Coal Trinco � � � � � � 1,389,158 2,762,515 3,432,695 4,085,520 4,731,238 5,362,898 4,997,539 5,177,463 4,792,426 4,288,351 3,724,778 4,150,202 3,704,946 3,327,489 CCHF CC�Heavy Fuel � � � � � � � � � � � � � � � � � � � � CCDL CC�Diesel � � � � � � � � � � � � � � � � � � � � CCLN CC�LNG � � � � � � � � � � � � � � � � � � � � COSB Coal�Subcritical � � � � � 1,566,064 1,343,686 865,570 778,654 709,935 657,114 638,135 378,186 618,296 399,813 246,698 140,377 334,185 245,012 193,013 COSP Coal�Supercritical � � � � � � � � � � � � 1,391,293 1,391,293 2,782,588 4,171,116 5,534,145 5,550,230 6,890,088 8,180,757 PUMP Pumped Storage (generation) � � � � � � � � � � � � � � � � � � � � Total Fuel Use 1,051,259 1,258,252 1,520,269 1,658,260 1,881,887 2,760,081 3,475,251 4,148,674 4,705,875 5,262,029 5,831,496 6,438,738 7,043,388 7,614,492 8,256,259 8,895,438 9,532,703 10,276,068 11,018,703 11,850,047 Total themal generation exc. NCRE 4,893 5,850 6,861 7,535 8,661 9,656 10,720 12,119 13,593 15,065 16,578 18,227 19,978 21,808 23,679 25,645 27,666 29,870 32,158 34,729 Spec. fuel consumpion (kg/kWh) 0.215 0.215 0.222 0.220 0.217 0.286 0.324 0.342 0.346 0.349 0.352 0.353 0.353 0.349 0.349 0.347 0.345 0.344 0.343 0.341 Sri Lanka: Environmental Issues in the Power Sector 198 ECA, RMA and ERM Detailed outputs from the model for the 15 cases Case 14: Fuel consumption in MT Case 14 NCRE forced with fuel price esc. 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 Existing and Committed Hydro plants Hydro1 � � � � � � � � � � � � � � � � � � � � Hydro2 � � � � � � � � � � � � � � � � � � � � New Hydro Plants Hydro3 � � � � � � � � � � � � � � � � � � � � Hydro4 � � � � � � � � � � � � � � � � � � � � Hydro Total � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � � Existing and Committed Thermal plants GTSM Small Gas Turbines 619 1,698 � � � � � � � � � � � � � � � � � � DSP Diesel Sapugaskanda 99,953 95,176 74,193 82,839 � � � � � � � � � � � � � � � � DSPX Diesel Sapugaskanda�Extension 97,637 97,637 97,614 97,625 97,628 83,868 41,593 11,891 27,693 25,271 9,690 23,761 23,793 37,185 11,946 11,720 � � � � GT7 Gas Turbine 7 2,832 6,329 1,220 3,988 25,904 232 216 20 313 � � � � � � � � � � � DLDL Lakdhanavi Diesel 32,114 21,454 9,699 14,445 � � � � � � � � � � � � � � � � DAPL Asia Power Diesel 76,971 74,783 62,412 67,173 72,865 30,757 10,495 1,171 6,750 � � � � � � � � � � � CCKP Kelanitissa Combined Cycle 20,737 30,443 8,200 23,151 80,387 5,253 1,921 221 2,245 3,448 717 5,051 6,629 10,509 3,915 10,511 5,506 7,987 4,988 8,456 CAES AES Combined Cycle 160,140 92,876 40,367 68,647 159,326 27,836 14,865 1,346 11,039 14,680 2,615 16,396 18,878 26,275 9,265 � � � � � DCPL Colombo Power Diesel 94,268 85,767 58,380 69,282 86,775 31,989 � � � � � � � � � � � � � � DHOR Horana Diesel 35,838 27,985 12,698 17,970 � � � � � � � � � � � � � � � � DMAT Matara Diesel 35,566 25,566 11,287 � � � � � � � � � � � � � � � � � DPUT Puttalam Diesel 140,908 139,805 125,101 132,547 136,975 68,767 � � � � � � � � � � � � � � DEMB Embilipitiya Diesel 154,658 127,538 69,395 95,247 136,276 41,596 � � � � � � � � � � � � � � GTKW Kerawalapitiya Gas Turbine 91,571 � � � � � � � � � � � � � � � � � � � CCKW Kerawalapitiya Combined Cycle � 393,972 384,971 389,800 391,980 274,204 93,979 18,843 70,528 67,418 18,484 64,415 70,834 78,978 35,521 42,526 22,147 29,566 17,842 27,907 CPUT Coal Puttalam � � 502,648 502,659 502,668 502,668 496,418 415,576 452,892 422,553 307,744 369,129 348,863 382,882 410,307 436,168 377,048 404,745 359,828 387,654 NCRE Existing and New RENW Renewables � � � � � � � � � � � � � � � � � � � � New Thermal Power Plants GT1 Gas turbine 1 � � � � 9,894 92 96 9 164 774 150 1,565 2,374 2,639 892 4,422 2,335 4,037 2,445 3,850 GT2 Gas turbine 2 � � � � � � � � � � � � � � � � � � � 2,183 GT3 Gas turbine 3 � � � � 40,473 1,138 515 73 723 1,250 265 2,221 3,184 8,910 3,247 10,132 5,394 8,769 5,282 9,985 CTRC Coal Trinco � � � � � � 1,388,963 2,739,087 2,757,941 3,421,404 4,614,093 4,703,200 5,319,743 5,400,317 5,455,720 5,496,723 5,310,369 5,394,819 5,173,184 5,289,147 CCHF CC�Heavy Fuel � � � � � � � � � � � � � 105,326 68,203 65,172 41,229 50,198 33,516 45,683 CCDL CC�Diesel � � � � � � � � � � � � � � � � � � � � CCLN CC�LNG � � � � � � � � � � � � � � � � � � � � COSB Coal�Subcritical � � � � � 1,542,685 1,227,374 678,468 940,682 835,365 470,069 705,921 676,224 882,469 1,634,835 2,193,368 1,720,255 2,311,079 1,907,412 2,555,077 COSP Coal�Supercritical � � � � � � � � � � � � � � � � 1,391,295 1,391,305 2,782,561 2,782,543 PUMP Pumped Storage (generation) � � � � � � � � � � � � � � � � � � � � Total Fuel Use 1,043,813 1,221,028 1,458,185 1,565,372 1,741,150 2,611,085 3,276,436 3,866,704 4,270,970 4,792,162 5,423,827 5,891,659 6,470,522 6,935,489 7,633,850 8,270,741 8,875,577 9,602,505 10,287,057 11,112,482 Total themal generation exc. NCRE 4,857 5,670 6,572 7,099 8,013 8,989 10,010 11,228 12,558 13,920 15,290 16,828 18,395 20,011 21,668 23,449 25,255 27,319 29,427 31,776 Spec. fuel consumpion (kg/kWh) 0.215 0.215 0.222 0.220 0.217 0.290 0.327 0.344 0.340 0.344 0.355 0.350 0.352 0.347 0.352 0.353 0.351 0.351 0.350 0.350 Sri Lanka: Environmental Issues in the Power Sector 199 ECA, RMA and ERM Detailed outputs from the model for the 15 cases Case 15: Fuel consumption in MT Case 15 Pumped storage allowed with DSM in 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 Existing and Committed Hydro plants Hydro1 � � � � � � � � � � � � � � � � � � � � Hydro2 � � � � � � � � � � � � � � � � � � � � New Hydro Plants Hydro3 � � � � � � � � � � � � � � � � � � � � Hydro4 � � � � � � � � � � � � � � � � � � � � Hydro Total � � � � � � � � � � � � � � � � � � � � � Existing and Committed Thermal plants GTSM Small Gas Turbines 752 1,733 � � � � � � � � � � � � � � � � � � DSP Diesel Sapugaskanda 99,962 95,253 75,838 � � � � � � � � � � � � � � � � � DSPX Diesel Sapugaskanda�Extension 97,637 97,637 97,567 97,623 97,623 88,025 56,343 17,976 16,936 16,608 31,908 17,085 34,122 21,161 4,090 9,168 � � � � GT7 Gas Turbine 7 2,979 6,081 1,139 11,192 11,192 24 36 6 7 � � � � � � � � � � � DLDL Lakdhanavi Diesel 32,297 22,856 10,390 � � � � � � � � � � � � � � � � � DAPL Asia Power Diesel 76,974 75,126 62,773 73,495 73,495 35,247 13,689 1,455 1,548 � � � � � � � � � � � CCKP Kelanitissa Combined Cycle 22,043 33,431 7,917 89,074 89,074 6,503 2,678 111 185 392 6,934 1,217 12,430 3,163 1,398 6,887 3,274 11,850 3,640 2,419 CAES AES Combined Cycle 164,369 98,851 39,722 170,392 170,392 37,361 24,982 1,695 1,956 2,649 28,823 6,112 36,013 9,274 4,024 � � � � � DCPL Colombo Power Diesel 94,485 86,448 64,279 88,016 88,016 38,831 � � � � � � � � � � � � � � DHOR Horana Diesel 36,154 28,544 13,949 � � � � � � � � � � � � � � � � � DMAT Matara Diesel 35,884 27,640 12,569 � � � � � � � � � � � � � � � � � DPUT Puttalam Diesel 140,910 140,168 124,909 137,384 137,384 81,331 � � � � � � � � � � � � � � DEMB Embilipitiya Diesel 155,465 132,341 76,821 141,248 141,248 51,811 � � � � � � � � � � � � � � GTKW Kerawalapitiya Gas Turbine 97,114 � � � � � � � � � � � � � � � � � � � CCKW Kerawalapitiya Combined Cycle � 393,963 383,556 392,251 392,251 304,414 131,921 31,523 37,193 40,364 100,388 40,043 104,573 49,623 16,223 45,468 25,523 51,696 41,322 43,096 CPUT Coal Puttalam � � 502,640 502,663 502,663 502,663 499,769 449,038 419,000 391,145 429,611 351,036 392,022 326,744 250,206 311,079 255,378 309,167 266,543 229,161 NCRE Existing and New RENW Renewables � � � � � � � � � � � � � � � � � � � � New Thermal Power Plants GT1 Gas turbine 1 � � � � � � � � � � � � 447 199 112 428 257 566 344 261 GT2 Gas turbine 2 � � � � � � � � � � � � � � � � � � � � GT3 Gas turbine 3 � � � � 71,090 1,604 354 49 77 174 2,223 553 7,249 2,218 1,173 4,302 2,580 6,135 3,242 2,459 CTRC Coal Trinco � � � � � � 1,389,134 2,758,252 3,423,658 4,073,183 4,115,299 5,342,879 5,425,468 5,159,344 4,776,567 5,118,042 4,663,959 5,124,461 4,671,863 4,211,356 CCHF CC�Heavy Fuel � � � � � � � � � � � � � � � � � � � � CCDL CC�Diesel � � � � � � � � � � � � � � � � � � � � CCLN CC�LNG � � � � � � � � � � � � � � � � � � � � COSB Coal�Subcritical � � � � � 1,556,160 1,338,230 860,962 783,042 708,821 978,838 655,796 911,456 638,457 382,357 641,994 450,899 695,880 549,631 431,238 COSP Coal�Supercritical � � � � � � � � � � � � � 1,391,293 2,782,597 2,782,587 4,173,912 4,173,884 5,565,182 6,953,200 PUMP Pumped Storage (generation) � � � � � � � � � � � � � � � � � � � � Total Fuel Use 1,057,026 1,240,073 1,474,071 1,703,336 1,774,426 2,703,977 3,457,138 4,121,067 4,683,604 5,233,335 5,694,024 6,414,721 6,923,781 7,601,475 8,218,747 8,919,953 9,575,781 10,373,637 11,101,766 11,873,188 Total themal generation exc. NCRE 4,921 5,764 6,640 7,207 8,177 9,400 10,643 12,009 13,500 14,957 16,509 18,118 19,848 21,737 23,563 25,906 27,788 30,568 32,635 34,908 Spec. fuel consumpion (kg/kWh) 0.215 0.215 0.222 0.236 0.217 0.288 0.325 0.343 0.347 0.350 0.345 0.354 0.349 0.350 0.349 0.344 0.345 0.339 0.340 0.340 Sri Lanka: Environmental Issues in the Power Sector 200 ECA, RMA and ERM Graphs of the results of the cases A11 Graphs of the results of the cases A11.1 Baseline Sri Lanka: Environmental Issues in the Power Sector 201 ECA, RMA and ERM Graphs of the results of the cases A11.2 LNG Sri Lanka: Environmental Issues in the Power Sector 202 ECA, RMA and ERM Graphs of the results of the cases A11.3 Hydro Sri Lanka: Environmental Issues in the Power Sector 203 ECA, RMA and ERM Graphs of the results of the cases A11.4 NCRE Sri Lanka: Environmental Issues in the Power Sector 204 ECA, RMA and ERM Graphs of the results of the cases A11.5 Green Sri Lanka: Environmental Issues in the Power Sector 205 ECA, RMA and ERM Graphs of the results of the cases A11.6 Forced supercritical Sri Lanka: Environmental Issues in the Power Sector 206 ECA, RMA and ERM Graphs of the results of the cases A11.7 No coal Sri Lanka: Environmental Issues in the Power Sector 207 ECA, RMA and ERM Graphs of the results of the cases A11.8 Pumped storage Sri Lanka: Environmental Issues in the Power Sector 208 ECA, RMA and ERM Graphs of the results of the cases A11.9 Demand-side management Sri Lanka: Environmental Issues in the Power Sector 209 ECA, RMA and ERM Graphs of the results of the cases A11.10 High demand Sri Lanka: Environmental Issues in the Power Sector 210 ECA, RMA and ERM Graphs of the results of the cases A11.11 High fuel prices Sri Lanka: Environmental Issues in the Power Sector 211 ECA, RMA and ERM Graphs of the results of the cases A11.12 Real fuel price escalation Sri Lanka: Environmental Issues in the Power Sector 212 ECA, RMA and ERM Graphs of the results of the cases A11.13 Low discount rate Sri Lanka: Environmental Issues in the Power Sector 213 ECA, RMA and ERM Graphs of the results of the cases A11.14 NCRE plus real fuel price escalation Sri Lanka: Environmental Issues in the Power Sector 214 ECA, RMA and ERM Graphs of the results of the cases A11.15 Pumped storage plus DSM Sri Lanka: Environmental Issues in the Power Sector 215 ECA, RMA and ERM Report on the stakeholder workshop A12 Report on the stakeholder workshop A workshop to discuss the Draft Report was held in Colombo on 18 November 2009. A total of approximately 130 invitations were issued and invitees were sent hard copies of the workshop agenda and the Executive Summary. Soft copies of the full Report were also sent to approximately 100 invitees126. Attendance at the workshop was excellent, with 85 participants plus the study team and support staff. The workshop was opened by Mr M. M. C. Ferdinando, Secretary, Ministry of Power and Energy and his opening address was followed by Mr. Gevorg Sargsyan, Task Manager from the World Bank. The discussion session was kindly moderated by Dr P. N. Fernando, former Manager of the Infrastructure, Energy and Financial Sectors Dept (East), at the Asian Development Bank. The workshop agenda is reproduced in Annex A12.1. Organisations represented at the workshop are shown in A12.2. In addition to verbal comments received during the workshop, participants were invited to submit written comments by 2 December. Notes of the verbal comments were prepared by Dr. Fernando and are provided in Annex A12.3. Written comments are reproduced in Annex A12.4. These comments have been taken into account in preparing this Draft Final Report. 126 Those for whom e-mail addresses were known. Sri Lanka: Environmental Issues in the Power Sector 216 ECA, RMA and ERM Report on the stakeholder workshop A12.1 Workshop agenda Environmental Issues in the Power Sector Stakeholder Workshop: Wednesday, 18th November 2009 Venue: Sri Lanka Foundation 100, Independence Square, Colombo 7. 8.30 am Registration 9.00 am Inauguration Address by Mr MMC Ferdinando, Secretary, Ministry of Power and Energy Address by Dr Sumith Pilapitiya Lead Environmental Specialist South Asia Sustainable Development Department, The World Bank 9.30 am Presentations 1. Overview of the Power Sector, on-going developments and long-term plans: Mr R J Gunawardana, Additional General Manager (Transmission), Ceylon Electricity Board 2. Review of electricity demand and the demand forecast: Mr Paul Lewington, ECA Ltd, UK 3. Policy options and scenarios studied, study results and implications: Dr Tilak Siyambalapitiya, Sri Lanka. 10.30 am Tea break 10.50 am Presentations (continued) 4. Analysis of coal requirements: Prof Peter Meier, Consultant, The World Bank 5. Environmental impacts of power plant siting, and review of Sri Lanka environmental regulations and standards: Mr Paul Lewington, ECA Ltd., UK 6. Multi-attribute trade-off analysis and study conclusions: Prof Peter Meier, Consultant, The World Bank 12.00 noon Discussion Moderated by Dr P N Fernando Former Manager Infrastructure, Energy and Financial Sectors Dept (East), Asian Development Bank 1.00 pm Concluding remarks by the consultants 1.15 pm Lunch This refers to the invitation to you by Secretary, Ministry of Power and Energy, to attend the above Workshop. The Executive Summary of the Draft Report of the Study is attached. We look forward to your presence on Nov 18th. For any clarifications, please call Mr M Anparasan (077 990 7194) or Ms Biddhika (011 230 1020). - Study Team Sri Lanka: Environmental Issues in the Power Sector 217 ECA, RMA and ERM Report on the stakeholder workshop A12.2 Organisations represented at the workshop Table 68 Organisations represented at the workshop Organisation name Aitken Spence Power PLC (IPP) Asia Power Ltd (IPP) Asian Development Bank Bioenergy Association Ceylon Electricity Board (CEB) Generation Planning Division Transmission Planning Division Environmental Unit Boradlands Hydropower Project Puttalam Coal Power Project Trincomalee Coal Power Project Upper Kotmale Hydropower Project Central Environmental Authority Centre for Environmental Justice (NGO) Ceylon Petroleum Corporation Energy Forum (NGO) Env Professionals Association of Sri Lanka (NGO) Environmental Foundation Ltd. (NGO) Hayleys Industrial Solutions PLC (IPP) Institution of Engineers, Sri Lanka Institute of Policy Studies Japanese International Cooperation Agency Lakdhanavi Ltd (IPP) Lanka Electricity Company (private) Ltd Ministry of Environment and Natural Resources Ministry of Finance and Planning Ministry of Power and Energy Open university of Sri Lanka Provincial Environmental Authority (North Western Province) Public Utilities Commission of Sri Lanka Senok Wind Power (Pvt) Ltd (SPP) Sri Lanka Energy Managers Association Small Power Developers Association Sustainable Energy Authority The World Bank Uma Oya Multi purpose Development Project, Ministry of Irrigation Sri Lanka: Environmental Issues in the Power Sector 218 ECA, RMA and ERM Report on the stakeholder workshop Organisation name University of Colombo University of Moratuwa University of Peradeniya University of Peradeniya University of Ruhuna University of Sri Jayewardenapura A12.3 Summary of comments at the workshop A short summary of questions/comments raised at the stakeholder workshop are provided below: Given the coal fired power plant commitments at Puttalam and Trincomalee and the multitude of additional such plant selected under the reference case, what are the true environmental damage cost implications and what are the specific impacts on agriculture? Why cannot biomass based power plant feature on a large scale in the generation expansion plan? The high fuel price scenario and consequent high tariff levels should result in significantly reduced demand due to price elasticity. Considering IPCC targets for reducing CO2 emission by 2030, how prudent is it to make commitments on a multitude of coal fired power plants with economic life extending for two to three decades beyond that date? Can trade off scenarios be developed to replace the CO2 emission attribute with another emission attribute? Heavy industry should be urged to utilize more energy efficient technology and lower the demand for electricity, and thereby reduce need for incremental power generating capacity. What would be the order of pumped storage capacity to be considered in the study? Why should not discount rates less than 10 percent be given greater significance? What action is being taken in the context of Uma Oya development to closely examine deterioration of the relevant watershed and its negative effects such as large scale transfer of silt? What is the economic life used for the medium size hydropower plant considered in the study? Why cannot the nuclear power option be considered at a later stage of the planning window? Sri Lanka: Environmental Issues in the Power Sector 219 ECA, RMA and ERM Report on the stakeholder workshop What is the status of environmental clearance for Stage 2 of the Puttalam Coal Fired Power Plant? Why cannot LNG terminal costs be distributed over other possible uses of gas also? Biomass as an indigenous resource should get priority for large-scale inclusion in the power generation expansion plan. There is an uneven playing field due to government sponsored coal fired power plant getting concessional financing and private sector sponsored biomass power plant having to access commercial financing. A12.4 Written comments on the Report Unedited, written comments received on the Report are provided below. We have identified the name of the institution making the comments but we note that these comments are not necessarily those of that institution. A12.4.1 Aitken Spence Power I think what you had presented is wonderful it predicts vital information that we need in the future for planning our development. As a person who had been in long time in biomass field i would say openly what you say is correct. Whatever engineering we talk about has to be economically justified. There are so many things we like in this world. But when we can't afford it we just have a look at it. Most people do not like to understand this. That is why we have argument and counter argument on this subject all the time in most important meetings. Having said that I do not see any problem with feeding chipped bio mass (suitably dry) along with coal. (At least 10% mix). Even though wood chips has lower calorific valve if you could price 60-75 USD/Mt would be more than enough for a wood chip having 20% moisture and calorific value 15000kj/Kg. My view is with this we can give a justifiable answer to wood business. I think since this is having no sulfur, over all sulfur balance can also maintain. It will be best justice you could do at this moment for the bio mass industry in this country mitigating controversial environmental effects of coal. Also the coal what we bring down is for the needed energy demand after purchasing more what country has at the moment. A12.4.2 Sustainable Energy Authority, Sri Lanka I noted that the off peak valley is going to be a major concern in years to come. Hence I would like your team to consider the following. (1) Find out a minimum off peak tariff for industries which can operate during the night. I am quite certain that some process industries would jump at the idea. (2) Offer a similar or even more attractive tariff for transport sector (primarily to charge batteries of electric cars, buses and bikes) and take out a substantial volume of transport energy from oil to coal. Sri Lanka: Environmental Issues in the Power Sector 220 ECA, RMA and ERM Report on the stakeholder workshop A serious analysis would definitely give out a positive economic output and a significant emission reduction. A12.4.3 Dept. of Chemical and Process Engineering, Uni. of Peradeniya I have concerned about the econometric methods used both by the CEB and the consultant in developing the models presented in Annex A of the report. I would appreciate it if you would mail the data used for developing the models so that I could show the problems in the model (which is very crucial for the report) used in the report. Page 116 of the report carries the following statement: Because this is a linear equation in the logarithmic quantities α and β can be estimated by simple linear regression' with reference to equation (2) appearing on the same page. The adjusted R-squared values of all models developed by the consultant from that point onward are very high, which is a clear indication that the use of simple linear regression is not acceptable for the system studied, which could be verified by evaluating the Durbin-Watson statistic of the models developed (which should be about 2.0 for the regression to be not spurious). I am certain that all these models will give Durbin- Watson statistics that are much below 1.0 which is a point that I could not verify without having access to the data used by the consultant in developing the models, which are the results of spurious regression and thus invalid. Please mail me all the data used by the consultant in developing these models and I shall show you the problem in the consultant's models. My calculations (carried out with World Bank data) show electricity demand far exceeding the values predicted by the consultant as well as by the CEB. A12.4.4 Public Utilities Commission of Sri Lanka I managed to go through most of it, considering the people involved, not surprised with the quality and coverage. CCGT(fuel oil) maintenance days; is it 56 or 82? I agree with these non realistic overnight capital cost estimates. I am surprised with the very little effort taken by CEB to arrive at the capital costs- they have a branch with 4-5 engineers working for a year on this plan! Also more sensitivity on this capital cost would be interesting, especially subcritical coal. Long-term price elasticity of electricity demand was higher in a previous study (by Mr. I. Jayatissa in 1994; -0.33) - normally it goes between -0.2 to -0.5, It would be interesting to see how this figure was arrived at, not necessarily for this study but for my curiosity? Also it would be better to recommend CEB to publish these assumptions on demand forecast and fuel prices, so that policy makers look at the LTGEP with care- it’s not a Bible. I understand that cities-Colombo have a day peak, hence DSM strategy for Colombo may have to be different to that of a suburb area? Consumer protection is within the Ministry of Power and energy/SEA per view, hence labelling can be justified. Possibility of exporting trinco-coal electricity via the undersea HVDC link? Sri Lanka: Environmental Issues in the Power Sector 221 ECA, RMA and ERM Report on the stakeholder workshop Apologies for my lack of knowledge; will this FGD be similar to low sulphur diesel at Sapugaskanda refinery; all the reduced sulphur emits at the refinery as opposed to by each vehicle on the road?-what happens to sulphur? What happens if the cement plant can't accommodate all the ash? Especially at 900MW-will we have colossal ash mountains as in India? A12.4.5 Bio Energy Association of Sri Lanka Based on the presentations made at the Stakeholder Meeting held on the 18th November 2009 and the draft study received, we give below our comments for the consideration of the Study Team. More details of the points raised and relevant documents are attached. i. The study report is not comprehensive as it ignores many relevant aspects of impacts on health and agriculture, caused due to the following emissions. a. Mercury Lead and heavy metals b. Highly toxic elements such as Cadmium and Arsenic c. Radio Active minerals d. Loss of Bio Diversity e. Desertification and land degradation ii. The world is going away from coal for many reasons not limited to the Climate Change, even in countries such as USA with large indigenous coal reserves. a. 157 coal plants costing US $ 45.3 Billion were cancelled in the USA 2000 to 2007. b. In 2008 additional 21 plants were canceled in USA and one in the Netherlands c. The energy giant EON canceled a 1000 MW coal power plant recently d. The problem of Mercury is receiving great attention in the world. In USA drastic measures are being taken to reduce the Mercury levels by 90%. There is no evidence if any effort is taken by Sri Lanka in this regard. e. The health hazards of Mercury is well known and were highlighted by Dr Granville Dharmawardene quoting the USA National Academy of Sciences as far back as 1980 f. According to Dr Dharamawardene 1000 MW of coal will also emit Radium 226 and Radium 228 both radioactive elements which will kill 25 people each year and cause respiratory diseases in 60,000 people .In fact the radiation from coal plants is supposed to be more lethal than form a Nuclear Power plant as there are no protection measures. What is the price of a human life and the loss of health? iii. The whole exercise is based on the assumption that the coal option would, yield low cost of generation. Accordingly the environmental and other impacts are given cursory considerations only. This evaluation should be done Sri Lanka: Environmental Issues in the Power Sector 222 ECA, RMA and ERM Report on the stakeholder workshop on the basis of the cost to the National Economy and not merely the cost to the utility. The costs involved in the treating patients affected by the health hazards and the long term cost of the effect on the agriculture has to be taken into account in the final cost. iv. It is not prudent for Sri Lanka to commit to the level of very high dependence on coal up to the 83% levels indicated and thus sacrifice the national energy security by dependence on a resource entirely out of our control both in terms of supply as well as costs. This runs counter to the very argument for diversification of energy resources and energy security. v. While Sri Lanka has many renewable resources such as bio mass and wind which if correctly evaluated on the basis of benefit for the national economy are far more advantageous and economical, such alternatives have not been considered in any of the scenarios presented. The assumptions made of which high cost of transport of bio mass fuel, once more demonstrates the total lack of appreciation of the Sri Lanka conditions. It is necessary to mention that two 100 MW power plants are operating even now based on total transport of fuel all the way from Colombo over distances exceeding 150 km. The assumption made that bio mass power is not economical is based on unsubstantiated assumptions, contrary to the fact that over 72% of the industrial energy needs are met form bio mass even now and moreover right now there is large scale fuel switching to bio mass form fossil fuels in this sector. vi. Evaluated on a level playing field and based on correct data and in the context of Sri Lankan economy, energy from bio mass is the cheapest option. We request you to perform this evaluation without prejudice before finalizing your report. vii. Where ever possible the generation of energy should be an industry by itself with maximum local input. This is completely absent in coal and oil plants as we do not have either resource locally. viii. The report claims to have based the finding on studies in India. This has no relevance to Sri Lanka as India has substantial coal reserves internally. If at all the study should compare a country which has to import all the coal. ix. The option of limiting the coal to the two sites Norochcolai ( 900 MW) and Trinco (500) is evaluated on the basis of the alternative being LNG and Oil . There is no explanation why this alternative cannot be from Bio mass and Wind. x. Under Options and Policies considered the contribution by NCRE is limited to 10% even after 2015. We would remember that in 2005 this figure of 10% was plucked out of thin air and forced on us with the promise that it will be reviewed in three years. Now four years have gone by. With no efforts to revise same nor has there been any conscious effort to develop this resource. As such the assumption that the contribution shall be limited to 10% even in year 2015 is not correct if cabinet decisions already made in this regard are implemented. Sri Lanka: Environmental Issues in the Power Sector 223 ECA, RMA and ERM Report on the stakeholder workshop xi. The cost of production of bio mass in Sri Lanka is significantly lower than that of coal on the basis of equivalent energy content. As such as the construction of the Norochcolai power plant is already commenced the option of co firing practiced in many countries should be incorporated as a mandatory condition. xii. If we follow this approach of replacing coal with biomass, a kg of wood may be delivered to Nurachcholai at Rs. 3.00 per kg at 20% mc. Adjusting for the calorific values (Coal 26,000 kJ/kg Vs. wood 13,000 kJ/kg), the brake even price of coal would be Rs. 6 per kg. But expected price of coal is Rs. 10 per kg. Hence wood is cheaper than coal. xiii. The national energy policy states that there shall be moratorium on any power projects using any fuel which is price indexed to the price of oil. It is now well established that the price of coal is closely linked to the price of oil. As such the recommendation of the study team to rely on large scale coal power generation blatantly violates this policy element. xiv. There is no mention on the plans for the disposal of the large quantities of solid wastes generated both by way of fly ash and bottom ash sludge from the FGD, which can cause immense environmental damage. The quantities must be quantified and very definite proposals must be made for their disposal. xv. The comments made regarding the effect of Sulfur Dioxide on the basis of the intensity per capita are highly illogical. The fact that the coal power plants are situated in the thinly populated areas does not give you the right to impose a health hazard on the rural populace. Although they are less in number the rural areas are more vulnerable with less resource to face the consequences. xvi. Further we submit that the effect of SOX should be evaluated in much greater depth on the negative effects on agriculture on which the Sri Lankan economy is based. xvii. The comments made such as that the emissions will be blown away to the sea illustrates the lack of understanding of the Sri Lankan conditions particularly the weather patterns. This argument is self defeating as one plant is on the western coast and the other in the eastern coast affected by two opposing monsoon winds. While the emissions from one plant may be blowing away to the sea the other will definitely be blowing inland. Further it must be understood that the oceans are also a part of the biosphere which has to be protected. xviii. The year 1990 has been identified as the base year on the global warming considerations when Sri Lanka had minimal levels of emissions. We have already increased this level by 230%. The two proposed power plants will make this 850% higher. As such if the global community imposes any restrictions the developing countries based on carbon emissions per GDP growth, in the coming years Sri Lanka would be at a great disadvantage to meet such strictures as at present our development has been by and large on low carbon technologies. Such large scale coal based power plants proposed the carbon intensity per GDP would rise sharply. Sri Lanka: Environmental Issues in the Power Sector 224 ECA, RMA and ERM Report on the stakeholder workshop We are ready to substantiate all of our above claims with data from internationally accepted sources. We attach here with some publications which refer to the problems and hazards mentioned in our submission. Which we hope you would study carefully. A12.4.6 Centre for Environmental Justice This is with reference to the request to send comments regarding the report entitled ‘Environmental Issues in the Power Sector’. As we are aware the Ceylon Electricity Board has recently put forward their future energy generation plan for the country. As usual the CEB is promoting Coal Fired Plants and justifies that coal is the best option for power generation in Sri Lanka. We consider your report as nothing but an attempt to justify the CEB generation plan. The report is completely coal biased and has not sufficiently analyzed the alternative energy sources such as wind, solar, wave, geothermal etc. On the face of an imminent climate catastrophe and seeing that burning of fossil fuel is the major reason for climate change, we expect that this report will critically look at the alternative options rather than promoting coal. It is a silly argument that Sri Lanka can still increase its CO2 emission since Sri Lanka is emitting less than many other countries. As we know Sri Lanka has increasing more than 230% its emissions since the Kyoto Protocol was signed. As we know the World Bank has increased funds over 102% for coal based power generation in the past few years and we have to consider this report as one step in that direction. The following are some key issues that need to be given further attention: In the reference case, it says that the per capita Carbon dioxide emission will be 1.3 tonnes. According to our calculations it should be at least 1.8 tonnes. So we would like to request the scientific calculation method of the above value. Also it states that, in China and US, the per capita emissions are 12 and 19 tonnes respectively. These values include Carbon dioxide emissions from coal and other industries including other emissions too. The value calculated here viz: 1.3 tonnes, is only from coal. Therefore 1.3 tonnes is not the final value and we like to know, what would be the national Carbon dioxide emission and what are the other development activities that largely contribute to increase in the emissions. The table under the ‘Environmental Issues Consequences of coal-fired Power Generation’ on emission standards with/without FGD seems to be unacceptable. 3% of Sulphur content of 800 and 400 mg/Nm3 with FGD, the tonnes of SO2 emission per year is same. This is not clear. We would like to have clarity on this. The analysis method of impacts to population and stack height is general and vague. It has to be analyzed after adopting a proper scientific method scientific modelling and state the area affected at different heights of the stack. Sri Lanka: Environmental Issues in the Power Sector 225 ECA, RMA and ERM Report on the stakeholder workshop We have advocated the CEB for preparing Strategic Environmental Assessment (SEA) in many occasions. However, it was not done. If we are to consider this report as an SEA, it needs further impacts analysis. If not we would like to know whether a separate SEA has been done for Energy sector plants with cumulative impacts. Although the first coal power plant of the country is yet to be completed, the emission standards have not developed yet. There are no recommendations to develop local environmental standards for coal power plants in this report. It is unfortunate that CEB does not respect the coal specification given in the EIA for Norochcholai coal power plant. The EIA and the approval agreed to have 0.65% sulphur in Coal. It is absurd to say that even 3% sulphur in coal is also acceptable. During the EIA stage we raised the issue that low sulphur coal will be not available all the time which will increase the cost of the power plant. Further we have learned that the per unit cost of the Norochcholai will be around Rs. 40. We would like to know the actual generation cost, actual transmission cost and actual environmental cost of Norochcholai power unit in justifying coal for Sri Lanka. We also like to know whether the CEB has done the EIA for the second and third coal generators which will be established in Norochcholai. We have noticed that the report gives high marks to the promotion of CFL bulbs. CFL has been recognized as an energy saving equipment and has several advantages over incandescent lamps. It uses about 75% less energy, lasts 8-10 times longer and produces 90% less heat while delivering more light per Watt. All the above facts are beneficial to the environment and also have a positive affect towards climate change by reducing energy consumption and emission of green house gases. However, CFL s contains Mercury which is classified as a hazardous material by US Environmental Protection Agency and other similar organizations. According to scientists, 1 mg of Mercury is enough to pollute a 20 acre lake. As each CFL contains 5mg of Mercury, without having an appropriate recycling facility promoting CFLs will become a risk. As we have calculated at least 75 kg of Mercury goes to the environment annually if each household disposes at least 5 CFLs per year. In our correspondence with the CEB and the CEA it was revealed that there is no facility to recycle CFL bulbs in Sri Lanka. We would be happy to see the environmental impacts of the CFLs due to this report. The report is entitled ‘Environmental Issues in the Power Sector’. However the report, only addressed the environmental issues of the coal power sector. We would like to know the possible impacts of other energy sources, including mini hydro, micro hydro, dendro power etc. The report only gives the names of the consultancy firms which are not acceptable to us. The value of the report will be based on not the agency but by the authors/ experts behind the report. Therefore we would like to know the authors of this document and a brief background of all these agencies. Centre for Environmental Justice is a public interest environmental organization working in the field of environmental law and advocacy. We thank you for this Sri Lanka: Environmental Issues in the Power Sector 226 ECA, RMA and ERM Report on the stakeholder workshop opportunity to bring our concerns on the report as well as the environmental problems in the power sector. We hope you will address our concerns when finalizing the report. We also would like to receive a written response to our concerns as early as possible. Further to our e mail dated 2nd December, 2009 regarding the above matter. According to the draft report, Chapter 7.2.5 under DSM intervention, the results are pending. If the consultants who drafted the report are continuing to analyze DSM cases and if the results of these analyzes are still pending, then it is not possible for the report to draw any conclusions about what is the best option for meeting Sri Lanka’s future energy demands. In Chapter 9, Implications for decision makers, it is stated as follows, ‘If cost is the only consideration, the reference case marked by coal as the dominant expansion technology (by 2025, coal will account for 83% of generation) would be the clear winner. In no other case are system costs lower’. This statement should not be a part of the report because the consultants have not finished the analysis of DSM cases. Therefore the report fails to assess whether investments in DSM is the best option of meeting Sri Lanka’s future energy needs. We hope you will address our concerns when finalizing the report. A12.4.7 Trincomalee Coal Power Project Office, Ceylon Electricity Board I have no major comments. However please check the units of the 1st column of table 43. Sri Lanka: Environmental Issues in the Power Sector 227 ECA, RMA and ERM