CEYLON ELECTRICITY BOARD
Eng. Buddhika SamarasekaraChief Engineer (Generation Planning)
Transmission and Generation Planning BranchTransmission Division
Ceylon Electricity BoardSri Lanka
May 2017
Sri Lanka’s Power Generation Expansion
Planning
SRI LANKA Total Area : 65,610 km2 Land Area : 62,705 km2 Population : 21.2 million Urban : 18.3% Rural : 81.7%
Population Density : 338 per/ sqkm Labour Force : 8.311 million Unemployment rate : 4.4% Literacy rate : 93.3% Life expectancy: 72 yrs (M), 78 yrs (F) Monetary Unit : Sri Lankan Rupee
(1 USD = 150 LKR at Jan 2017)
INTRODUCTION
Gross Domestic Product : 11,839 billion LKR (Market Prices)
GDP per capita : 3,835 US$ (Market Prices) GDP structure 2016 Agriculture – 7.1% Industry – 26.8% Services – 56.5% Taxes less subsidies on products – 9.6%
SRI LANKAN POWER SECTOR
Installed capacity 4065 MW
Peak Demand 2483 MW
Electricity Generated 14249 GWh
System Losses 10.28 %
Elec. Consumption per Capita 603 kWh
Level of Electrification 98.71%(June 2016)
DISCUSSION TOPICS
• Generation Planning Methodology & Tools
• Scenario Analysis
• Contingency Analysis
• NDC Planning
4
DIMENSIONS OF ELECTRIC SYSTEM PLANNING
5
Short(<5 years)
Medium(5-10 years)
Long(>10 years)
Demand
Generation
Transmission
Distribution
AREA OF INTERESTIN GENERATION
EXPANSION PLANNING
CATE
GO
RY O
F EL
ECTR
IC
SYST
EM P
LAN
NIN
G
AREA OF INTERESTIN TRANSMISSION
PLANNING
5
• Planning Period: 20 Years (2018-2037)
• Study Period: 25 Years (2018-2042)
• Planning Criteria:
– Loss of Load Probability: Maximum 1.5%
– Reserve Margin: Minimum 2.5% & Maximum 20%.
• Unserved Energy Cost
• Discount Rate– 10% discount rate
6
LONG-TERM GENERATION EXPANSION PLAN
2011 value (Reference-PUCSL ) - 0.5 $/kWh2017 escalated Value - 0.663 $/kWh (98.07 Rs/kWh)
Preparation of Demand Forecast
Update existing and committed generating system data
Screen available generating technology options
Assess the hydro system capabilities using SDDP model
Study on Integration of Renewable Based Generation
Formulate and prepare the generation expansion planusing WASP IV (In future Optgen-sddp Model)
Analysis of robustness and feasibility of the plan
Contingency Analysis
STUDY PROCESS
7
DEMAND FORECAST 2018-2042
8
BASE FORECAST
9
Base Load Forecast = Time Trend Forecast + (Econometric Forecast + External Effects)External effects of the Temperature variation and Tariff adjustments were analyzed andconsidered.
10000
15000
20000
25000
30000
35000
40000
45000
50000
55000
Gen
erat
ion
(GW
h)
Year
Base Load Forecast
Distribution Divions Forecast
Year 2017 2018 2019 2020 2021All Distribution Divisions (GWh) 14,967 16,171 17,282 18,704* 19,822*
Time Trend (GWh) 15,160 16,188 17,285 18,456 19,370
*These two figures are high due to the consideration of the demands of Megapolis Projects andother new developments. However, average 5.9% growth is forecast during 2018-2022.
14,000
15,000
16,000
17,000
18,000
19,000
20,000
21,000
2017 2018 2019 2020 2021
Gen
erat
ion
(GW
h)
Year
All Distribution Divisions (GWh)
Time Trend Forecast (GWh)
DomesticSector
IndustrialSector
CommercialSector
Other
• GDP Per Capita
• Number of Domestic Consumer Accounts in previous year
• Industrial Sector Gross Domestic Product• Previous year Electricity demand of Industrial consumer category
• Service Sector Gross Domestic Product• Previous year Electricity demand in Commercial consumer category
• Time-trend analysis
LONG TERM FORECAST
Methodology
• Econometric modelling has been adopted by CEB for the PERIOD 2021-2040• Sales figures of the past were analysed against following independent
variables.
10
ACTUAL AND FORECAST ENERGY/PEAK DEMAND
11
0
1000
2000
3000
4000
5000
6000
7000
8000
9000
0
5000
10000
15000
20000
25000
30000
35000
40000
45000
50000
Dem
and
(MW
)
Ener
gy (G
Wh)
Generation
Peak Demand
ForecastActual
As per Draft LTGEP 2018-2037
BASE DEMAND FORECAST
12
Year Demand Net Loss* Net Generation Peak Demand(GWh) (%) (GWh) (MW)
2017 13656 9.92 15160 25852018 14588 9.88 16188 27382019 15583 9.84 17285 29032020 16646 9.81 18456 30772021 17478 9.77 19370 32082022 18353 9.73 20331 33462023 19273 9.69 21342 34912024 20242 9.65 22404 36432025 21260 9.61 23522 38042026 22332 9.58 24697 39722027 23459 9.54 25933 41492028 24639 9.50 27225 43352029 25867 9.46 28570 4527
2030** 27164 9.42 29990 47262031 28388 9.38 31328 49392032 29637 9.35 32692 51572033 30926 9.31 34099 53812034 32251 9.27 35546 56122035 33642 9.23 37063 58542036 35090 9.19 38642 61072037 36613 9.15 40302 63722038 38165 9.12 41992 66422039 39733 9.08 43699 69152040 41324 9.04 45431 71932041 42967 9.02 47227 74812042 44700 9.00 49121 7784
5 Year Average Growth (2018-2022) 5.9% 5.9% 5.1%10 Year Average Growth (2018-2027) 5.4% 5.4% 4.7%20 Year Average Growth (2018-2037) 5.0% 4.9% 4.5%25 Year Average Growth (2018-2042) 4.8% 4.7% 4.4%
* Net losses include losses at the Transmission & Distribution levels and any non-technical losses, Generation (Including auxiliary consumption) losses are excluded. This forecast will vary depend on the hydro thermal generation mix of the future.** It is expected that day peak would surpass the night peak from this year onwards
GENERATION OPTIONS
13
EXPECTED HYDRO ENERGY POTENTIAL
0
1,000
2,000
3,000
4,000
5,000
6,000
100%97
%94
%91
%88
%85
%82
%79
%76
%73
%70
%67
%64
%61
%58
%55
%52
%49
%46
%43
%40
%37
%34
%31
%28
%25
%22
%19
%16
%13
%10
%7%4%1%
GWh
Annual Total Average
4050 GWh
Obtained using SDDP Model
FUTURE GENERATION OPTIONS -CONVENTIONALCandidate Hydro Plants
• Seethawaka Hydro Power Plant - 20MW / 48GWh• Gin Ganga Hydro Power plant - 20MW / 66GWh• Thalpitigala Hydro Power Plant - 15MW / 52.4GWh
35 MW Auto Diesel fired gas turbines 105 MW Auto Diesel fired gas turbines 150 MW Auto Diesel fired combined cycle plants 300 MW Auto Diesel fired combined cycle plants 300 MW Coal fired Power Plants 600MW Super Critical Coal fired Power Plant 300 MW Natural Gas fired combined cycle plants 600 MW Nuclear plants
Candidate Thermal Plants
15
SCREENING CURVESThermal Generation Options
16
0.00
20.00
40.00
60.00
80.00
100.00
120.00
140.00
0% 10% 20% 30% 40% 50% 60% 70% 80%
Uni
t Cos
t (U
Scts
/kW
h)
Plant Factor (%)
GT35 MW
GT105 MW
CCY150 MW
FO Engines 15MW
CCY300 MW
Nuclear 600MW
LNG 150MW
LNG 300 MW
SUPC 600MW
New Coal 300 MW
SCREENING CURVESOther Renewable Options
17
0.00
10.00
20.00
30.00
40.00
50.00
60.00
70.00
0% 10% 20% 30% 40% 50% 60% 70% 80% 90%
Uni
t Cos
t (U
Scts
/kW
h)
Plant Factor (%)
Solar with battery 10MW (Solar Capital Cost = USD 1400/kW)
Dendro 5 MW
Solar with battery 10MW (Solar Capital Cost = USD 900/kW)
Solar 10MW (Capital Cost = USD 1400/kW)
Solar 10MW (Capital Cost = USD 900/kW)
Wind 20MW
OTHER RENEWABLE ENERGY MODELLING
18
19
LOAD CURVE
Inclusion of ORE in the Long Term Generation Expansion Plan
0500
100015002000250030003500
Load
/MW
Time
0500
100015002000250030003500
Load
/MW
Time
Wind & SolarOther
According to the estimated wind and solar resource profiles, the demand profiles were modified to reflect both capacity and energy contributions from these ORE power plants.
LOAD CURVE
20
Maximum Wind & Solar Contribution
Minimum Wind & Solar Contribution
0
500
1000
1500
2000
2500
3000Lo
ad/M
W
Time
Wind & SolarOther
0
500
1000
1500
2000
2500
3000
3500
Load
/MW
Time
Wind & Solar
Other
21
LOAD DURATION CURVE
Inclusion of ORE in the Long Term Generation Expansion PlanAccording to the adjusted demand profiles, the Load Duration Curves (LDC) were adjusted and used as inputs for expansion studies.
0.00
0.20
0.40
0.60
0.80
1.00
0.00 0.10 0.20 0.30 0.40 0.50 0.60 0.70 0.80 0.90 1.00
PU L
oad
PU Time
After Wind+Solar adjustment
Original
LTGEP 2018-2037• 300 LDC’S represents 25 year planning horizon instead of 25 LDC’s used in
previously.• Both Capacity and Energy Contribution taken in to consideration.
PROJECTED DEVELOPMENT OF OTHER REBased on RE Integration Study 2016/17
Year Mini Hydro(MW)
Wind (MW)
Biomass(MW)
Solar(MW)
Cumulative Total NCRE Capacity
Total NCRE (MW)
Share of NCRE from Total Generation
2018 344 144 39 210 737 13%2019 359 194 44 305 902 14%2020 374 414 49 410 1246 18%2021 384 489 54 465 1392 19%2022 394 539 59 471 1463 20%2023 404 599 64 526 1592 20%2024 414 644 69 581 1708 20%2025 424 729 74 685 1912 21%2026 434 729 79 740 1982 20%2027 444 754 84 795 2076 20%2028 454 799 89 900 2242 20%2029 464 824 94 954 2336 20%2030 474 894 99 1009 2476 20%2031 484 929 104 1064 2580 20%2032 494 974 104 1119 2691 20%2033 504 1044 109 1173 2830 20%2034 514 1114 109 1229 2965 20%2035 524 1184 114 1283 3105 20%2036 534 1279 114 1338 3265 20%2037 544 1349 119 1442 3454 20.6%
22
PROJECTED DEVELOPMENT OF OTHER RE
23
0.0%
5.0%
10.0%
15.0%
20.0%
25.0%
30.0%
0
1000
2000
3000
4000
5000
6000
7000
8000
9000
10000
2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037
Ener
gy S
hare
(%)
Ener
gy (G
Wh)
Year
Solar (MW) Wind (MW)
Biomass (MW) Mini Hydro (MW)
Other renewable energy share (%)
FORMULATE AND PREPARE THE GENERATION EXPANSION PLAN
24
WASP-IV METHODOLOGY
25/40
Cost Function Minimization Using Linear Programming Method
Load forecast
Existing systemCandidate unitsConstraints• Reliability• Implementation• Environment• Fuel availability
etc.
INPUTOUTPUT
Time
• Build schedule• Generation• Fuel consumption• Costs• Emissions
WASP-IV
WASP determines the Generating System Expansion Plan that meets demand at minimum cost, while satisfying certain user specified constraints for the system:
26/40
DETERMINATION OF NECESSARY CAPACITIES
MW
Years
Annual peak load
Annual peak load +Minimum reserve margin
Annual peak load +Maximum reserve margin
Critical LOLP
Area of optimization
Capacity of existing system
WASP optimal capacity
New necessary capacity
DISPATCH ANALYSIS
28
Long Term- Hydro Thermal Optimization (SDDP Software)
Operational Study
• Optimum use of hydro resource and the corresponding operation of thermal power plants are simulated at monthly time step.
• Future Hydro conditions are predicted using probabilistic methods
5429 5193 5532 5961 6794 7039 7555 8978 9276 10250 107263127 3556 3784 3409
3415 3679 37663396 3421
3766 35634773 5174 4599 5089 4713 4764 4948
4560 51634877 5466
2288 2649 3470 3777 4209 45904799
52485471
56175963163 256
293294
0
5000
10000
15000
20000
25000
30000
2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028
Ener
gy/G
Wh
Year
PSPP
OtherRenewable
Large Hydro
OtherThermal
Coal Thermal
Summary of Generation
29
Short Term Dispatch Analysis (NCP Software)
Operational Study
0
500
1000
1500
2000
2500
3000
3500
MW
Time (30 Minutes)
Large hydro
Other oil
SC/CC GT
Wind_P
Wind_N
Wind_M
Wind_E
Wind_H
Solar_K
Solar_H
Mini_Hydro
Biomass
TPCL2
TPCL1
LVPS3
LVPS2
LVPS1
Demand
2022 High Wind period Week Day
ANALYSIS OF BASE CASE PLAN
0
2000
4000
6000
8000
10000
12000
Capa
city
(MW
)
Total Installed Capacity
Total Dispatchable Capacity at the Critical Period
Demand
DISPATCHABLE CAPACITY AT CRITICAL PERIOD BASE CASE
SENSITIVITY & SCENARIO STUDIES
Robustness of the economically optimized plan was Investigated byanalyzing its sensitivity to changes in the key input parameters.
32
Power system planners are expected to predict the future and they have to provide decision makers with information that would facilitate making sound decisions.
Scenario/Sensitivity Study RemarksScenarios
Reference Case No future OREFuel Diversification
Future Coal Power Development Permitted up to 1800 MWNo Future Coal Power Development Permitted
Energy Mix with NuclearSensitivities on Base Case
Demand VariationHigh Demand 1% higherLow Demand 1% lower
Discount Rate VariationHigh Discount 15%Low Discount 3%
Fuel Price Escalation Based on IEA forecastWEO 2016
COMPARISON OF ENERGY SHARE IN 2037
10%
21%
53%
14%2%
Base Case
11%4%
69%
15%1%
Reference Case
10%
21%
41%
26%
1%
Future Coal Power Development
Limited to 1800 MW
11%
20%
13%
56%
No FutureCoal Power
Development
10%
21%
34%
14%
19%
2%
Energy Mix with
Nuclear
Major Hydro
ORE
Thermal - Coal
Thermal - Oil
Thermal - LNG
Nuclear
PSPP
COMPARISON OF CAPACITY SHARE IN 2037
15%
31%
32%
4%
13%
5%
Base Case
18%
7%
47%
16%
6%6%
Reference Case
15%
31%
8%
42%
4%
No Future Coal Power
Development
15%
32%
23%
20%
4%6%
Future Coal PowerDevelopment
Limited to1800 MW
15%
32%
20%
13%
4%
6%
10%
Energy Mix with Nuclear
Major Hydro
ORE
Thermal - Coal
Thermal - LNG
Thermal - Oil
PSPP
Nuclear
INVESTMENT ANALYSIS
SENSITIVITY ANALYSIS
36
050
100150200250300350400450500550600650700
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
Cons
truc
tion
Cost
(USD
mill
ion)
Year
Local costForeign cost
0.0
500.0
1000.0
1500.0
2000.0
2500.0
3000.0
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
2037
Tota
l Ann
ual C
ost (
USD
mill
ion)
Year
Base Case
No Future Coal Power Development PermittedScenario
Annual Cost Comparison USD Million
Investment Plan for Base Case
ENVIRONMENTAL IMPACT ANALYSIS
Comparison of SOx, NOx, PM & CO2 Emissions
-
5
10
15
20
25
30
2018
2020
2022
2024
2026
2028
2030
2032
2034
2036
CO2
(Mill
ion
tons
)
Year
Base Case Scenario
Reference Scenario
Future Coal Power Development Limited to 1800MW Scenario
No Future Coal Power Development Scenario
Energy Mix with Nuclear Scenario
0.0
1.0
2.0
3.0
4.0
5.0
6.0
7.0
2018
2020
2022
2024
2026
2028
2030
2032
2034
2036
Part
icul
ate
Mat
ter (
1000
tons
)
Year
0
10
20
30
40
50
60
70
80
90
100
2018
2020
2022
2024
2026
2028
2030
2032
2034
2036
SO2
(100
0 to
ns)
Year
0
5
10
15
20
25
30
35
40
45
2018
2020
2022
2024
2026
2028
2030
2032
2034
2036
NO
x (1
000
tons
)
Year
Cost Impacts of CO2 Emission Reductions
-
50,000
100,000
150,000
200,000
250,000
300,000
-
2,000
4,000
6,000
8,000
10,000
12,000
14,000
16,000
18,000
CO2
Emis
sion
(kT)
Cost
(Mil
US$
)
PV Cost USD mil
CO2 kT
3.72
8.28
11.48
9.74
0.00
2.00
4.00
6.00
8.00
10.00
12.00
14.00
USD
/ C
O2
Ton
Compared with Reference Case
40
ENVIRONMENTAL ASPECTSComparison of CO2 Emissions from Fuel CombustionIEA CO2 Emissions from Fuel Combustion (2016 Edition)- 2014 data
Country kg CO2/2010 US$ of GDP
kg CO2/2010 US$ of GDP Adjusted to
PPP
Tons of CO2 per Capita
Total CO2 Emissions(Million tons)
Sri Lanka 0.23 0.08 0.81 16.7Pakistan 0.67 0.17 0.74 137.4
India 0.92 0.29 1.56 2019.7Indonesia 0.46 0.17 1.72 436.5Thailand 0.64 0.24 3.6 243.5
China 1.08 0.53 6.66 9134.9France 0.10 0.17 4.32 285.7Japan 0.21 0.27 9.35 1188.6
Germany 0.20 0.21 8.93 723.3Switzerland 0.06 0.09 4.61 37.7
USA 0.32 0.32 16.22 5176.2Brazil 0.20 0.16 2.31 476
Australia 0.26 0.36 15.81 373.8World 0.44 0.32 4.47 32381
2014 2025 2030 2037No Future
Coal 6.79 5.05 7.68 12.08
Coal Limited1800 MW 6.79 6.41 10.72 17.05
Base Case 6.79 7.41 11.32 19.25
Reference 6.79 9.33 13.55 24.20
Total CO2 Emissions (Million tons) from Electricity –Actual and Predicted in Scenarios
42%
5%19%
24%
10%
Electricity and heatproduction
Other energy ind.own use
Manufacturingindustries andconstructionTransport
Other sectors
41%
0%6%
48%
5%
World Sri Lanka
CONTINGENCY ANALYSISAnalysis of the impact of both controllable and uncontrollable risk events, which could lead to inadequacy of supply to meet the capacity and energy demand in immediate future years from 2018 to 2022.
1. Variation in Hydrology2. Variation in Demand3. Delays in implementation of Power Plants4. Long period outage of a Major Power Plant
Single occurrence of these risk events were considered at first and then simultaneous occurrence of several events were analysed to identify the short term energy and capacity shortage.
INDC Submitted to UNFCCC
42
• DETERMINATION OF INDC’sBusiness As Usual (BAU) : Only existing NCRE power plants as at 1st January 2015 were included without committed major hydro developments.Reference Case : Only existing NCRE power plants as at 1st January 2015 were included. Base Case: 20% Energy share from Non-Conventional Renewable Energy (NCRE) considered from 2020 onwards.
(4,000)
(3,500)
(3,000)
(2,500)
(2,000)
(1,500)
(1,000)
(500)
-
500
2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025
CO2
/100
0 to
ns
Emission reduction from INDC
Emission reduction from NationalCommitment
4% nationalcommitment
16% from INDC
NDC PRESENT STATUSGovernments agreed a long-term goal of keeping the increase in global averagetemperature to well below 2°C above pre-industrial levels and to aim to limit the increaseto 1.5°C
Sri Lanka ratified in September 2016
Energy Sector INDCs which was prepared based on LTGEP 2015-2034 stated that Sri Lankaexpects 4% unconditional and 16% conditional reduction of greenhouse gas emissionswith compared to Reference scenario in 2030
-
5
10
15
20
25
30
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
2037
CO2
(Mill
ion
tons
)
Year
RECOMMENDATIONS FOR VARIABLE RENEWABLE ENERGY INTEGRATION
• Day ahead, hourly basis Wind and Solar PV energy forecasting system• 24 hour (round the clock), Renewable Energy Desk
Technical assistance expected from financing agencies to develop Renewable Energy Desk
• Variable Renewable Energy (VRE) curtailment rights to system operatorCompensation mechanism has to be studied to future VRE plants.
• Planned network strengthening projects must be completed as scheduled.
• Future base load power plants should be designed to de-load in order to keep the VRE curtailment at a minimum level.
• The ORE locations should be prioritized based on the plant factors, availability and cost of transmission network and developed accordingly
• If the proposed conventional plants are not commissioned as scheduled, the VRE addition in the plan has to be revised accordingly. Thus it is proposed to review this planning methodology once in two years.
44
SRI LANKAN CONTEXT IN CLIMATE CHANGETOWARDS LOW CARBON DEVELOPMENT STRATEGY• Amendment of National Energy Policy to absorb more ORE
• Nationally Determined Contributions (NDCs)
• Contribution from Renewable Energy
• Clean Development Mechanism
• Carbon Partnership Facility
• Fuel Quality Road Map
• Loss Reduction in Transmission & Distribution Network
• Demand Side Management & Energy Conservation
45
THANK YOU
46