2. A STUDY ON ENVIRONMENTAL & UTILITY PLANNING IMPLICATIONS OF DISTRIBUTED POWER GENERATION FOR A REGIONAL ELECTRICITY BOARD OF INDIA S.C. Srivastava, B.K. Barnwal Indian Institute of Technology, Kanpur-208016, India Dharam Paul, Praveen Gupta Environ. & Energy Conservation Div. Central Electricity Authority, New Delhi-110066, India R.M. Shrestha, R.Shrestha Energy Program, Asian Institute of technology Pathumthani-12120, Thailand A.K. Srivastava Illinois Institute of Technology, Chicago, USA

3. Mitigating Environmental Emissions from the Power Sector: Analyses of Technical and Policy Option in Selected Asian Countries (Funded by Swedish International Development Agency) Issue#1:Least cost supply side option for mitigating GHG and other harmful emissions from the power sector subject to emission target Issue#2: Identification of some CDM projects in the power sector and assessment of their GHG and other harmful emission mitigation potential Issue#3: Environmental implications of IPPs and decentralized power generation

4. Objective Optimal generation expansion plan under the conventional least cost planning strategy (business as usual case} with and without DSM ( TRP & IRP cases ) To study the change in optimal generation expansion plan with DPGs introduced as existing and candidate plants. Impact of DPGs on total cost of generation expansion and also on emission of different Green House Gases in NREB system. Sensitivity Analyses with respect to some key parameters related to DPG plants.

5. Methodology Least cost generation expansion plan minimizes cost of power generation from existing and candidate power plants and installing candidate power plant over certain period. If Mathematically, least cost generation expansion plan minimizes following objective function,

6. Where,

8. System constraints are : Power demand constraint: Sum of power generation by all power plants (existing and candidate) in each block of the planning horizon will be greater than or equal to total projected power demand during that period. Reliability constraint: Power demand from all the plants (candidate + existing) must be greater than or equal to the sum of power demand and the reserve margin in each year Annual energy constraint: Annual energy constraint are defined to limit the energy generation of each thermal plant according to the capacity, availability and time required for schedule maintenance of the plant.

9. Hydro energy constraint: Total energy output of each hydro plant should not exceed the pre specified energy limit in each season. Fuel or resource availability constraint: Limit to the energy generation of the plants by particular fuel types if such limitations exist during the planning horizon. Annual emission constraint: The annual emission level of each pollutant from total generation system should not exceed the pre-specified value of each year

10. Utility load shape and demand forecast Existing and candidate plant data of utility DPG plants Generation Expansion plan using IRPA with Utility supplying utility load (BAU case) Generation Expansion Plan using IRPA with Utility + DPG plants supplying total load Generation Mix (G 1 ) Total Cost (C 1 ) CO 2, SO 2 and NO x Emissions (E 1 ) Change in Emissions = E 1 +E 0 ~E 2 Change in Cost = C 1 +C 0 ~C 2 Change In Generation mix = G 1 ~G 2 Generation Mix (G 1 ) Total Cost (C 1 ) CO 2, SO 2 and NO x Emissions (E 1 ) Flowchart for IRPA with DPG

11. Case Studies Four case studies have been done : 1. Traditional Resource Planning (TRP) without any DPG plant (The TRP cases do not include any DSM options) 2. Traditional Resource Planning with DPG plants. 3. Integrated Resource Planning (IRP) without any DPG plant (The IRP cases include DSM options). 4. Integrated Resource Planning with DPG plants. using Input data of Northern Regional Electricity Board (NREB), and Integrated Resource Planning Analysis (IRPA) developed by Asian Institute of Technology and CPLEX as software tool

12. NREB system NREB is one of the five Regional Electricity Boards (REBs) of India Consists of seven State Electricity Boards (SEB) REBs exist to promote the integrated operation between SEBs of that Region Electricity generation in India is predominantly thermal base with hydro-thermal mix of 25:75 in year 1996-1997 Installed generating capacity in NREB as on March 2000 was 25847 MW Transmission and Distribution losses in the country stood at 21% in year 1996-1997 ( Transm. Loss appx. 4%)

13. NREB system has 160 Thermal plants and 230 Hydro plants at present including 29 existing DPGs each of hydro kind. Present generation capacity of NREB system:(March, 2000) Thermal plants : 17239 MW, Hydro plants : 7698 MW, Nuclear plants : 910 MW, Total : 25847 MW Country utilizes power reliability indices - Loss of Load Probability (LOLP) of 2% and Energy Not Served (ENS) not to exceed 0.15% in expansion planning Projected peak demand of NREB for 2001-2002 is 31375 MW Projected energy requirement of NREB for year 2001-2002 is 181649 GWh Study considers five types of DSM options, 3 candidate DPGs based on renewable sources viz. wind, solar and micro-hydro.

14. Estimated potential of renewable in India Energy Source Estimated Potential Wind Energy 20000 MW Solar Energy 5*10 15 kWh/pa Biomass17000 MW Source: Naidu, 1996

15. Input data and assumptions Planning horizon : 2003-2017 Base year : 1998 Discount rate : 10% Two seasons are taken in a year with season 1 of July, August, September and season 2 of rest of the months Reserve margin is taken as 5% for all the year Ten types of fuels are taken as gas, nuclear, lignite, oil and six grades of coal Two types of clean supply side options - Pressurized Fluidized Bed Combustion (PFBC) and Integrated Gasification Combined Cycle IGCC are considered. (By using PFBC and IGCC technology efficiency can be improved up to 45%.)

16. Seven types of candidate thermal plants, two types of supply side options, three types of DPG plants and 21 candidate hydro plants are considered. Peak load forecast for planning horizon is shown in table 1. Table 1: Projected Peak Load In NREB System YearPeak Load (MW) Energy Reqrmnt (GWh) 200333800 203169 200744009 254161 201260077 350185 201782000 482488

17. A-1: Candidate Thermal Plants Name Coal 4 -500Coal 6 -500CCGT –500 Nuclear - 500 PFBC -450IGCC -400 BIGCC-132 Fuel type usedCoal 4Coal 6GasNuclearCoal 6 Wood Fuel consumption rate unit 000’kg/ MWh 000’kg/ MWh 000’m3/ MWh 000’gm/ MWh 000’kg/ MWh 000’kg/ MWh 000’kg/ MWh Fuel Consumption 0.7 0.20.0270.51 Calorific value (kBtu/kg) 13.5 41.7440635015.56 19.21 CO2 emission factor (kg/MWh) 1026 550090755171.64 SO2 emission factor (kg/MWh) 660.400.2550.2350.918 NOx emission factor (kg/MWh) 2.5 1.6400.6 Installed capacity (MW) 500 250500450400132 Earliest available year 20042005200320072005 Annual allowable Maximum unit 854580610 Availability 0.71 0.80.580.85 Unit depreciable Capital cost (k$) 450000 175000600000510000500000162875 Unit non- depreciable Capital cost (k$) 50000 1950066000525005000018100 Heat rate at full load (Mcal/MWh) 2500 20622777201318502469 Operating cost (k$/MWh) 0.0012 0.00080.00150.00120.00130.0174 Annual maintenance hour 864 1296896864 Fixed O&M cost (k$/MWmonth 221.672.72.22.325.4 Candidate thermal plants

18. Candidate Hydro Power Plants NameCapac.YearUnitCostEn.Sea.1En. Sea.2 Hibra12020072143555187200280800 Palamaneri1002007442265137900256100 Budhil3520082377295720085800 L. Nagpala2502008282109339325630175 Kuther13020092119444188200282300 Uhl st. III50201024901980400120600 Maner Bali762010484512115850215150 T. Vishnugadh1202010356465185033343633 Parbati III16720103106071266266399400 Dhauliganga II702010390683111416206916 Kishanganga11020113100529102500239166 Kotlibhel2502012472508473462879287 Uri II7020124137877108450253050 Bursar25020144144632121950284550 Shahpur Kandi16820141299177333440708560 Sewa st II60201423825847250110250 Pakhal dul250201545994144250103250 Kishau1202015515355592890172510 Parbati I25020153278000391200586800

19. Name Capacity (MW) EA Year Avail.Opearting Cost FixedO&M (000’$/ MWmonth) Generation pattern Season1Generation pattern Season2 Karnah-I120030.8701.860.41660.3276 Karnah-II120030.8701.860.41660.3276 Stakna-I220030.8701.860.41660.3276 Stakna-II220030.8701.860.41660.3276 chennani-II-I120030.8701.860.41660.3276 chennani-II-II120030.8701.860.41660.3276 Sal st II-I120030.8701.860.55540.2808 Sal st II-II120030.8701.860.55540.2808 gumma-I1.520030.8701.860.55540.2808 gumma-II1.520030.8701.860.55540.2808 charanwala1.220030.8701.860.41660.3276 pugal 11.520030.8701.860.41660.3276 RMC mangrol-I220030.8701.860.41660.3276 RMC mangrol-II220030.8701.860.41660.3276 RMC mangrol-III220030.8701.860.41660.3276 suratgarh-I220030.8701.860.41660.3276 suratgarh-II220030.8701.860.41660.3276 chitaura-I1.520030.8701.860.48600.3042 chitaura-II1.520030.8701.860.48600.3042 salwa-I1.520030.8701.860.48600.3042 salwa-II1.520030.8701.860.48600.3042 galogi-I120030.8701.860.48600.3042 galogi-II120030.8701.860.48600.3042 chirkilla120030.8701.860.48600.3042 urgam-I1.520030.8701.860.48600.3042 urgam-II1.520030.8701.860.48600.3042 nirgajni-I2.520030.8701.860.48600.3042 nirgajni-II2.520030.8701.860.48600.3042 Existing DPG hydro plants

20. NameMicrohydro-2Solar PV -2Wind -2 Fuel type usedWaterSolarWind CO2 emission factor (kg/MWh)000 SO2 emission factor (kg/MWh)000 NOx emission factor (kg/MWh)000 Installed capacity (MW)222 Earliest available year2003 Annual allowable Maximum unit50050 Availability0.870.250.35 Unit depreciable Capital cost (k$)2222.260001400 Unit non-depreciable Capital cost (k$)000 Operating cost (k$/MWh)00.00120.00075 Annual maintenance hour0168240 Fixed O&M cost (k$/MWmonth1.862.51.35 Candidate DPG plants

21. Demand Side Management Options SectorDSM Options Residential 1: Replacement of 100 W incandescent bulb by 20W CFL 2: Replacement of 60W incandescent bulb by 11W CFL 3: Replacement of 40W incandescent bulb by 9W CFL Agriculture 4: Replacing inefficient pumps by efficient ones 5: Partial rectification of pumps

22. RESULTS ( NREB System)

23. Capacity Mix (%) by Plant Types TRP without DPG TRP with DPG IRP without DPG IRP with DPG Hydro24.7 26.5 Coal43.3 46.445.9 CCGT21.520.624.622.3 Nuclear1.91.01.11.6 Lignite0.4 0.5 PFBC4.2 0.91.4 IGCC3.8 0.0 Solar-0.0- Wind-0.9-1.0 BIGCC0.10.00.10.0 Micro Hydro-0.9- Total Capacity (GW) 106.5106.499.499.5

24. Generation Mix (%) by Plant Types TRP without DPG TRP with DPG IRP without DPG IRP with DPG Hydro20.320.426.226.3 Coal51.951.752.651.1 CCGT13.312.818.216.6 Nuclear2.01.01.31.9 Lignite0.5 0.7 PFBC6.3 0.81.3 IGCC5.6 0.0 Solar-0.0- Wind-0.9-1.2 BIGCC0.10.00.1 Micro Hydro-0.7-0.8 Total Gen. (TWh)477.9476.1370.3368.4

25. Technology Options (Number of Units) Selected TRP without DPG TRP with DPG IRP without DPG IRP with DPG Coal 4 60 59 Coal 6000 0 CCGT736979 70 Nuclear200 1 PFBC10 2 3 IGCC10 0 0 BIGCC101 0 Solar-0- 0 Wind-500- Micro-hydro-500- 471 Capacity Utilization and Unserved Energy of the System TRP without DPG TRP with DPG IRP without DPG IRP with DPG Average Capacity utilization 51.8252.5048.4749.29 Av. Unserved Energy (MWh) 3.20825.24211.862113.205

26. Expansion Costs During Planning Horizon Expansion Cost (M$) TRPwitho ut DPG TRP with DPG IRP without DPG IRP with DPG Capital cost (1)13409.413302.211689.411731.0 Fixed O&M (2)6829.06804.46519.86506.8 Fuel and Variable (3)26505.326018.322757.122114.7 Fuel and O&M (2+3)33334.332822.729276.928621.5 Sub total (1+2+3)46743.746124.940966.340352.6 DSM cost (4)0.0 707.5 Total Cost (1+2+3+4)46743.746124.941673.841060.1 Average Incremental Cost (AIC) of Generation AIC (US cents/kWh) TRP without DPG TRP with DPG IRP without DPG IRP with DPG Without DSM 2.86 2.802.682.60 With DSM 2.86 2.802.862.78

27. Environmental implications Total environmental emissions Emissions TRP without DPG TRP with DPG IRP without DPG IRP with DPG CO 2 (Gkg)3166.63122.92636.42548.5 SO 2 (Mkg)15998.316039.914416.813992.8 NO x (Mkg)8220.28186.27297.37066.3

28. Sensitivity Analyses Sensitivity analyses are carried out by varying the capacity-cost of candidate DPG plants- Solar, Wind and Micro-hydro. 1.Solar plants were selected when their capacity cost was reduced to 0.5 $/W P (for both TRP and IRP cases) from 3 $/W P. 2.Wind plants were selected even up to the capacity cost of 9000 $/kW for IRP case and 3000 $/kW for TRP case (against the base value of 700 $/kW). 3.Micro-hydro plants were found to remain cost- effective even when their unit capacity cost was increased by 120% of their base value.

29. Conclusions With introduction of DPG plants, capacity mix of CCGT decreases. Solar plants were not selected in any of the cases, while all wind plants were selected for both the TRP and IRP cases. All the micro- hydro units in TRP case and most in the IRP case were selected. · With the introduction of DPG, the reliability of the system worsens. · Introduction of DPG plants reduces CO 2, SO 2 and NO x emission except the SO 2 in TRP case. Capital cost decreases in the case of TRP, while it increases in the case of IRP. It reduces the fuel and O&M cost, total expansion cost & average incremental cost. Thus, one can expect reduction in electricity price with the introduction of DPG plants. · Solar plants are not selected in any of the cases due to their higher capacity cost. They get selected only when the capacity cost is lowered to 0.5 $/W p · Micro-hydro power plant units get selected even by increasing the capacity cost by 120% of its base value. Even when the capacity cost of wind units are increased to 3500 $/kW for the TRP case and to 9500 $/kW for the IRP case, they get selected. The wind power plant is most economically feasible plant among all the three considered DPG plant types.

30. Thank you