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