The integration of renewable based generation into Sri Lankan grid

Integration of Renewable Based Generation into Sri Lankan Grid 2017-2028

Eng. Dr. H. M. Wijekoon, Chief Engineer Transmission Planning Eng. Buddhika Samarasekara, Chief Engineer (Generation Planning) Transmission and Generation Planning Branch Transmission Division Ceylon Electricity Board Sri Lanka

ANNUAL RENEWABLE ENERGY CAPACITY ADDITIONS MW 400

Average Annual Absorption 37 MW / year

Average Annual Absorption 145 MW / year

350

300

250

200

ANNUAL RENEWABLE ENERGY CAPACITY ADDITIONS

150

100

50

2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037

0

Year

Average Annual Absorption of Other Renewables is nearly four times higher than the past.

2

Requirement of RE integration Study  NCRE generation especially intermittence based sources like wind and solar power cannot be controlled  Energy from these types of generating facilities must be taken “as delivered”, which necessitates the use of other controllable resources.  Conventional resources must then be used to follow the net of electric demand and NCRE energy delivery.  Conventional recourses also provides essential services such as regulation and contingency reserves that ensure power system reliability.  To the extent that NCRE based generation increases the required quantity of these generating services, additional costs are incurred.

The questions to be addressed in NCRE integration ď ą To what extent would NCRE generation contribute to the electric supply capacity needs for CEB? ď ą What are the costs associated with scheduling and operating conventional generating resources to accommodate the variability and uncertainty of NCRE based generation?

NCRE integration study Summary

OTHER RENEWABLE ENERGY Present Status (as at 28th February 2017) No of Projects

NCRE Technology 1 Mini Hydro Power

Capacity (MW)

178

349.64

4

13.08

3 Biomass - Dendro Power

5

11.02

4 Solar Power

7

41.36

5 Wind Power

15

123.85

209

543.5

2

Biomass - Agricultural & Industrial Waste

Total

5

Historical ORE Contribution Annual Energy Contribution from ORE Projects Energy Generation (GWh) Year ORE

Capacity (MW)

System Total

ORE

Total System Installed

Capacity

2003

120

7612

39

2483

2004

206

8043

73

2499

2005

280

8769

88

2411

2006

346

9389

112

2434

2007

344

9814

119

2444

2008

433

9901

161

2645

2009

546

9882

181

2684

2010

724

10714

212

2818

2011

722

11528

227

3141

2012

730

11801

320

3312

2013

1178

11962

367

3355

2014

1215

12418

442

3932

2015

1466

13154

455

3850

2016

1160

14250

516

4018

ORE Project Development –Capacity Additions Up to 15.11.2016

6

RENEWABLE ENERGY- PRESENT STATUS Renewable Energy Contribution Major Hydro

Other RE

Total RE Percentage

8000

70%

7000

60%

6000 50%

40% 4000 30% 3000 20% 2000 10%

1000

0

0% 2006

2007

2008

2009

2010

2011 Year

2012

2013

2014

2015

2016

7

Percentage

Energy (Gwh)

5000

Study Methodology (1) Generation Planning with ORE,

(2) System operation study and (3) Power system analysis study incorporating ORE generation

Renewable Energy Resource Estimation

9

Data Source and Data requirement  Generation and transmission planning studies  Transmission planning study files for selected cases  Data files used for CEB generation planning  Half hourly historical demand data and projected system demand and loss data for the period considered for the study.  Existing NCRE generation  Hydro generation constraints  10 mins wind data for five regions (Mannar, Puttlam, Nothern, Eastern and Hill country)  10 mins solar radiation data for Hambantota and Kilinochchi  5sec solar power output data from existing solar plants  SPPA signed, LOI issued all NCRE projects  Details on existing conventional power plants (capacity, reactive power capability, efficiency, ramp up and ramp rate etc.)  Merit order dispatch  Transmission Network data (Steady state and dynamic data)  Operation restrictions such as minimum operation of base load plants, water release, plant outputs etc.  Pump storage data  Other data like hydrology, inflows etc.

PRESENT CAPACITY MIX AS AT DECEMBER 2016 Capacity Share in 2016 Other RE 13% IPP Thermal 16% CEB Coal 22%

30.00

Energy Share in 2016 Other RE 8% CEB Hydro IPP 24% Thermal 15%

Total RE 47% CEB Hydro 34%

CEB Coal 36%

CEB Thermal 15%

CEB Thermal 17% 1 USD= 154 LKR On 18.5.2017

Actual Average Unit Cost of Electricity Generation 2016 28.37

25.00 Unit Cost (LKR/kWh)

Total RE 32%

20.00

Average cost at selling point in 2016 = 18.09

15.00

Average cost at selling point in 2015 = 15.06

24.34 17.59

10.00 5.00

2.32

6.58

CEB Hydro

CEB Coal

Renewables Generation Technology

CEB Thermal

IPP Thermal

11

Energy Mix during last 10 years 14000 1466

12000 723

Energy (GWh)

346 3082

345

3529

435

1977

548 3600

3680

2336

2083

4000 4292

3703

3359

1225 2610

4906 5493 4898

2532 3433

2091

4991 3605

1215

2795 1394

1669

4254

3884

6000

2000

1176

729

10000 8000

734

6012 4905

4021 2729

3634

0 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 Year CEB Hydro CEB Thermal IPP Thermal NCRE

Renewable Energy Resource Estimation ď ś Major Hydro Total Hydro Energy Estimation based on past 30 years data 6000

5243

5000 4155

GWh

4000 3233

3000 2000 Annual Total

Weighted Average considering worst hydro conditions

1000

4% 8% 12% 16% 20% 24% 28% 32% 36% 40% 44% 48% 52% 56% 60% 64% 68% 72% 76% 80% 84% 88% 92% 96% 100%

0 Duration (%)

New Projects in the Pipeline

Estimated Energy for different hydo conditions

35 MW Broadlands

20 MW Seethawaka

120 MW Uma Oya

15 MW Thalpitigala

Very Wet

31 MW Moragolla

20 MW Gin Ganga

5243 4917

Wet

Medium

4004

Dry

Very Dry

3611

3233 13

Renewable Energy Resource Estimation ď ś Mini Hydro Monthly Average Mini-Hydro Production Per Unit Monthly Average Capacity

0.6

Capacity (p.u)

0.5

0.45

0.4

0.49

0.46 0.42

0.51

0.45 0.41

0.37 0.29

0.3 0.23

0.2

0.16

0.18

0.1 0

Jan

Feb

Mar

Apr

May

Jun Jul Month

Aug

Sep

Oct

Nov

Dec

ďƒ˜ Seasonal variation is derived based on Historical Data 14

Renewable Energy Resource Estimation 2. Wind Five wind regimes are modelled based on site measurements for wind Production estimation Wind Regime 1

Northern

2

Mannar

3 4

Puttalam Eastern

5

Hill Country

Location Jaffna Pooneryn Nadukuda Nannattan Silawathu Udappuwa Kokilai Seethaeliya Balangoda 15

Renewable Energy Resource Estimation 2. Wind  Wind measurement data is collected for each wind regime  Wind plants are modelled for each wind regime  Wind plant production is estimated  Use System Advisory Model (SAM) for wind and solar profile estimation 20 18 16 14 12 10 8 6 4 2 0

2nd Week of May

2nd Week of October

1 238 475 712 949 1186 1423 1660 1897 2134 2371 2608 2845 3082 3319 3556 3793 4030 4267 4504 4741 4978 5215 5452 5689 5926 6163 6400 6637 6874 7111 7348 7585 7822 8059 8296 8533

speed 9m/s))

Example : Production of Mannar 25MW Wind Block

Hours

16

1 284 567 850 1133 1416 1699 1982 2265 2548 2831 3114 3397 3680 3963 4246 4529 4812 5095 5378 5661 5944 6227 6510 6793 7076 7359 7642 7925 8208 8491

Capacity (MW))

Wind Plant Power output

25

20

15

10

5

0 Hours

Output Variation of 10 MW Wind Power Plant in Putlam

Renewable Energy Resource Estimation 2. Wind Wind Plant modelling main parameters

Block Capacity Turbine capacity (MW)

Mannar

Puttalam

Hill Country

Northern

Eastern

25MW

20MW

10.45MW

20MW

20MW

2MW x10

0.55MW x19

2MW x10

2MWx10

91%

91%

91%

91%

91%

Nadukuda 2015

Udappuwa 2009-2010

Seethaeliya 2012-2014

Pooneryn 2015

80

80

50

80

2.5MW x10

Plant availability Wind measurement Data (location -Year) Hub Height (m)

Kokkilai 2015 80

Results on Wind plant modelling Mannar

Puttalam

Hill country

Northern

Eastern

Block Capacity

25MW

20MW

10MW

20MW

20MW

Annual Plant Factor

36.7%

31.4%

19.1%

34.1%

37.3%

Annual Energy(GWh)

80

55

17

59.7

47.9

19

Renewable Energy Resource Estimation

3. Solar

Two Solar regimes are modelled based on data for production estimation Location

Plant Factor

Hambantota

16.3%

Kilinochchi

15.6%

20

Renewable Energy Resource Estimation 3. Solar Sample Solar measurement data ( 1 minute time step) in Kilinochchi.

1400 Solar Irradiance (W/m2)

1200

19th Jan

9th Feb

11th March

1000 800 600 400 200 1 59 117 175 233 291 349 407 465 523 581 639 697 755 813 871 929 987 1045 1103 1161 1219 1277 1335 1393

0

Mins 21

Renewable Energy Resource Estimation 4. Biomass Biomass Plants are considered as dispatchable power plants and modeled as thermal plants

22

Optimized Generation Expansion Plan

23

ACTUAL AND FORECAST ENERGY/PEAK DEMAND As per Draft LTGEP 2018-2037 50000

9000

45000

Actual

8000

Forecast

40000

7000

30000

5000

25000 4000

20000 Generation

15000

3000

Peak Demand

10000

2000

5000

1000

Estimation of avg. growth rate approx. 5 %

2042

2040

2038

2036

2034

2032

2030

2028

2026

2024

2022

2020

2018

2016

2014

2012

2010

2008

2006

2004

0 2002

0

Demand (MW)

6000

2000

Energy (GWh)

35000

Three main cases of long term generation expansion plans were developed for the purpose of this study.

1 2

3

Reference Case Case 1 Case 2

Only the existing “other renewable energy� is included and No future ORE development is assumed Expansion plan with new coal development up to 1200MW, with pump storage development Expansion plan without both pump storage development and coal development

NCRE Projection Year

Mini Hydro (MW)

Wind (MW)

Biomass (MW)

Solar (MW)

Total ORE Capacity (MW)

Annual Total ORE Generation (GWh)

Share of ORE from Total Generation %

2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028

329 344 359 374 384 394 404 414 424 434 444 454

144 244* 294 414 489 539 599 644 729 729 754 799

34 39 44 49 54 59 64 69 74 79 84 89

50 210 305 410 465 471 526 581 685 740 795 900

557 837 1002 1246 1392 1463 1592 1708 1912 1982 2076 2242

1793 2425 2792 3402 3784 4022 4338 4620 5084 5229 5447 5796

12.2% 15.5% 16.8% 19.6% 20.8% 21.0% 21.6% 21.9% 23.0% 22.5% 22.3% 22.6%

* According to the latest implementation schedules, 100MW Wind Park in Mannar considered for the year 2018 above is expected to be commissioned in July, 2019.

26

PROJECTED DEVELOPMENT OF OTHER RENEWABLE ENERGY 9000

Solar (MW)

Wind (MW)

Biomass (MW)

Mini Hydro (MW)

Other renewable energy share (%)

25.0%

8000 7000

Energy (GWh)

30.0%

20.0%

6000 5000

15.0%

4000 10.0%

3000 2000

5.0%

1000 0

0.0% 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037

Year

As per Draft LTGEP 2018-2037

27

Energy Share (%)

10000

Reference Case 2017-2028 YEAR

2017

2018

2019

2020 2021 2022

RENEWABLE ADDITIONS (MAJOR HYDRO)

-

120 MW Uma Oya HPP

35 MW Broadlands HPP 15 MW Thalpitigala HPP 31 MW Moragolla HPP 20 MW Seethawaka HPP 20 MW Gin Ganga HPP

2023

-

2024

-

2025 2026 2027 2028

1x200 MW Pump Storage Power Plant 1x200 MW Pump Storage Power Plant 1x200 MW Pump Storage Power Plant -

THERMAL ADDITIONS 100 MW Furnace Oil fired Power Plant 1* 70 MW Furnace Oil fired Power Plant 2* (Southern Region) 2x35 MW Gas Turbine 1x35 MW Gas Turbine 1x300 MW Natural Gas fired Combined Cycle Power Plant – Western Region+ 1x300 MW Natural Gas fired Combined Cycle Power Plant – Western Region 1x300 MW Natural Gas fired Combined Cycle Power Plant – Western Region

THERMAL RETIREMENTS

LOLP %

-

0.631

8x6.13 MW Asia Power 4x17 MW Kelanitissa Gas Turbines

1.494

4x18 MW Sapugaskanda diesel

0.756

6x5 MW Northern Power

0.261

100 MW Furnace Oil fired Power Plant 1* 70 MW Furnace Oil fired Power Plant 2*

163 MW AES Kelanitissa Combined Cycle 163 MW Combined Cycle Power Plant (KPS–2)  Plant  1x300 MW New Coal Power Plant Phase I, 115 MW Gas Turbine Trincomalee -2 4x9 MW Sapugaskanda Diesel Ext. 1x300 MW New Coal Power Plant Phase I, Trincomalee -2 4x9 MW Sapugaskanda Diesel Ext. 4x15 MW CEB Barge Power Plant 1x300 MW New Coal Power Plant Phase II, Trincomalee -2 1x300 MW New Coal Power Plant - Southern

0.898 0.996

0.850

0.452

0.971 0.109

-

0.235

-

0.079

New Coal Development Restricted to 1200MW, First Coal Plant by 2023 YEAR

2017

2018

2019

2020 2021 2022

RENEWABLE ADDITIONS (MAJOR HYDRO)

-

120 MW Uma Oya HPP

35 MW Broadlands HPP 15 MW Thalpitigala HPP 31 MW Moragolla HPP 20 MW Seethawaka HPP 20 MW Gin Ganga HPP

THERMAL ADDITIONS 100 MW Furnace Oil fired Power Plant 1* 70 MW Furnace Oil fired Power Plant 2* (Southern Region)

-

2024

-

2025 2026 2027 2028

1x200 MW Pump Storage Power Plant 1x200 MW Pump Storage Power Plant 1x200 MW Pump Storage Power Plant -

LOLP %

-

0.477

2x35 MW Gas Turbine

8x6.13 MW Asia Power 4x17 MW Kelanitissa Gas Turbines

0.535

1x35 MW Gas Turbine 1x300 MW Natural Gas fired Combined Cycle Power Plant – Western Region+

4x18 MW Sapugaskanda diesel

0.270

-

6x5 MW Northern Power

0.364

-

-

0.731

1x300 MW Natural Gas fired Combined Cycle Power Plant – Western Region

100 MW Furnace Oil fired Power Plant 1* 70 MW Furnace Oil fired Power Plant 2*

0.609

163 MW Combined Cycle Power Plant (KPS–2)

163 MW AES Kelanitissa Combined Cycle Plant  115 MW Gas Turbine 4x9 MW Sapugaskanda Diesel Ext.

0.551



2023

THERMAL RETIREMENTS

1x300 MW New Coal Power Plant Phase I, Trincomalee -2 1x300 MW New Coal Power Plant Phase I, Trincomalee -2

-

4x9 MW Sapugaskanda Diesel Ext. 4x15 MW CEB Barge Power Plant

0.318

0.339

-

-

0.283

-

-

0.462

-

0.169

1x300 MW Natural Gas fired Combined Cycle

(No Coal Development & No PSPP Development) YEAR

2017

2018

2019

2020 2021

2022

RENEWABLE ADDITIONS (MAJOR HYDRO)

-

120 MW Uma Oya HPP

-

THERMAL ADDITIONS 100 MW Furnace Oil fired Power Plant 1* 70 MW Furnace Oil fired Power Plant 2* (Southern Region) 2x35 MW Gas Turbine

LOLP %

-

0.477

8x6.13 MW Asia Power 4x17 MW Kelanitissa Gas Turbines

1x35 MW Gas Turbine 1x300 MW Natural Gas fired Combined Cycle 4x18 MW Sapugaskanda diesel Power Plant – Western Region+

35 MW Broadlands HPP 15 MW Thalpitigala HPP

-

31 MW Moragolla HPP 20 MW Seethawaka HPP 20 MW Gin Ganga HPP

THERMAL RETIREMENTS

-

6x5 MW Northern Power -

1x300 MW Natural Gas fired Combined Cycle 100 MW Furnace Oil fired Power Plant 1* Power Plant – Western Region 70 MW Furnace Oil fired Power Plant 2*

163 MW AES Kelanitissa Combined Cycle Plant  1x300 MW Natural Gas fired Combined Cycle 115 MW Gas Turbine Power Plant – Southern Region 4x9 MW Sapugaskanda Diesel Ext. 1x300 MW Natural Gas fired Combined Cycle Power Plant – Southern Region 1x300 MW Natural Gas fired Combined Cycle 4x9 MW Sapugaskanda Diesel Ext. Power Plant - Western Region 4x15 MW CEB Barge Power Plant 1x300 MW Natural Gas fired Combined Cycle Power Plant - Western Region 1x300 MW Natural Gas fired Combined Cycle Power Plant -Southern Region

0.535

0.270

0.364 0.731

0.609

163 MW Combined Cycle Power Plant (KPS–2) 

2023

-

2024

-

2025

-

2026

-

2027 2028

-

0.547

0.322 0.293 0.698

0.504 0.385

Power System Operational Study The objective of the operational study is to analyze (1) System integration impacts and any associated costs including the generation upgrades (2) Operational measures and ancillary services required for increased integration of wind and other renewable energy (ORE) technologies

Annual Energy (GWh) Monthly energy in 20 blocks

System operation study approach

Repeat process for each year 3 times (dry, high wind and wet period) for the period 2017-2036

Run SDDP (Stochastic Dual Dynamic Program) for multiple years & obtain relevant period Future Cost Function (Wind, Solar, Biomass and Minihydro are dispatched continuously according to the given profile since they are modelled as zero cost plants)

Monthly Future Cost function Run NCP for 2 days per month (Weekday & Weekend) for each period for multiple years

-Obtain daily plant dispatch schedule at 30 minutes time step -Curtailment requirement of other renewable plants outputs if any

Load Forecast 2017-2041

- Irrigation Requirement - Water Value of Reservoirs - Hydro inflow forecast methodology - Fuel Prices - Power Plant maintenance Schedule - Forced Outages - Power plant operation characteristics - Power plant additions/retirements -Annual Other RE capacity development - Annual profiles of wind and solar from SAM (System Advisor Model) hourly resource - Biomass annual profile - Mini hydro annual profile

-Monthly Future Cost Function of the SDDP -Half an hourly load forecast -Hydro Plant parameters and configurations -Thermal Plant parameters and configurations -NCRE generation profile 30 min -Daily inflows to the reservoirs in half an hour intervals -Daily Maintenance schedule and outages -Irrigation and other water releases requirements -Spinning reserve requirements -Initial state of the system for initiating the simulation

Operational Study Long Term- Hydro Thermal Optimization (SDDP Software)  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 30,000

Energy (GWh)

25,000

20,000 2,314

15,000 4,131 -

10,000

4,750

5,000

1,664 4,175

4,317

563 3,210

546

733 4,109

5,035

4,627

1,853

2,514

3,477

3,670

3,961

5,021

5,051

5,099

5,097

5,064

4,421

4,583

6,059

467 2,066

4,375

8,757

8,121

8,241

8,435

8,651

4,304

4,471

4,867

5,039

5,146

5,451

5,584

5,306

5,339

5,457

5,679

5,276

1,407 2,342 6,435

4,746

-

-

5 3,750

4,813

2,109

22

39 4,964

2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028

Large Hydro

Other Renewable

Coal Thermal

LNG Thermal

Other Thermal

PSPP

33

Percentage share of Other Renewable Energy sources 100%

30 171

share of Other renewable (%)

90%

666

805

805

948

1087

1087

1231

Solar 873

238 1375

273

50%

1536

1752

1923

2059

Wind 2379

2379

2454

2583

308

40%

20%

523

401

60%

30%

523

401

80% 70%

312

Biomass 343

1,065

378

413

449

484

1,113

519

554

589

624

1,372

1,405

1,437

1,469

1,162 1,210

1,243

1,275

1,307

10%

1,340

0% 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028

Year

MiniHydro

Short Term Dispatch Analysis using NCP software  NCP software tool was used to simulate daily dispatch of selected days in 30 minute time step  The curtailment requirement of renewable energy production was identified.  All the system constraints were modelled according to the present operational procedures of the system control center.  The inputs that were used for the model and specified constraints are mentioned later in this section.

Operational Study • Input Data o o o o o o o o o o o o o o o o

Hydro Inflow Data 44 years (38 Gaging station) Demand Data (20 years) Plant characteristics Renewable Profiles Fuel characteristics and Prices Irrigation Requirement Water Value of Reservoirs Fuel Prices Power Plant maintenance Schedule Plant Forced Outage rates Power plant operation characteristics Power plant additions/retirements Annual Other RE capacity development Annual profiles of wind and solar (hourly Data) Biomass annual profile Mini hydro annual profile 36

Operational Constraints • -

Hydro Power Plants Unit Generation and turbine outflow constraints Reservoir operation constrains Cascade hydro plant topologies Drinking Water/Irrigation requirements Must run Hydro power plants Generation Reserves for frequency control operation Spinning reserve from all hydro plants

• -

Thermal Power Plants Minimum loading level constraints Lakvijaya Coal Power plant – 190 MW (70%) New Coal Power Plant – 135MW (50%) Kelanithissa Combined cycle plant -75MW (45%) Westcoast Combined cycle plant -108MW (40%) Sojitz Kelanithissa Combined cycle plant -70MW (44%) Plant Startup Costs and Minimum Up time and Minimum Down time (hours) Maximum ramp up and Maximum ramp down rates (MW/min)

System Operational Constraints -

Half hourly demand requirement Energy deficit is not allowed Total secondary Spinning reserve requirement is specified.

Largest Generation unit online should not be greater than 30% of the system load.

•

Renewable Power Plants

-

Must run condition for wind, biomass, solar and Mini hydro Curtailment is allowed at instances where above constraints cannot be met

Assumptions -

Future plant additions and retirements are according to the optimized expansion plan

-

“Other Renewable� generation sources were considered as Non Dispatchable plants for the estimation of curtailment requirement

-

Future Wind Solar and Mini-hydro Generation profiles were estimated based on measured data and past performance assuming no significant variation for future years

-

Maintenance plans of major power plants (Coal fired and Combined cycle Plants) for future years as per the maintenance scheduling procedure

Operational Study Short Term Optimization (NCP Software)  Daily Economic dispatch of power plants are simulated at 30 min time step .  System operational limitations are identified  When the generation constraints cannot be satisfied, excess amount of renewable energy is curtailed  a given year was divided in to three periods to capture the seasonality effects of hydro conditions, renewable variations and demand variations JAN

FEB

MAR

Dry Period

APR

MAY

JUN

JUL

High Wind Period

AUG

SEP

OCT

NOV

DEC

Wet Period

• total 36 simulations were carried out for 2018, 2020, 2022, 2024, 2025, 2028

40

Daily dispatch of other renewables and curtailments 2020 High Wind period Week Day 3000 2500

1500 1000 500

Time (30 Minutes)

Biomass Total wind Curtailment requirement

Minihydro Total soalr PSPP Pump

22:30

21:00

19:30

18:00

16:30

15:00

13:30

12:00

10:30

9:00

7:30

6:00

4:30

3:00

1:30

0 0:00

MW

2000

Curtailment for 2020 High Wind period Week Day 160 140 120

MW

100 80 60 40 20 0

1 3 5 7 9 11 13 15 17 19 21 23 25 27 29 31 33 35 37 39 41 43 45 47

Curtailment‌

Time (30 Minutes)

2020 High Wind period Weekend Weekend day 3000 2500 2000

1000 500 0 0:00 1:00 2:00 3:00 4:00 5:00 6:00 7:00 8:00 9:00 10:00 11:00 12:00 13:00 14:00 15:00 16:00 17:00 18:00 19:00 20:00 21:00 22:00 23:00

MW

1500

Time (30 Minutes)

Biomass Total wind Curtailment requirement Demand

Minihydro Total soalr PSPP Pump PSPP Generation

2020 High Wind period Weekend Curtailment of VRE Weekend day 90

Curtailment requirement

80 70

MW

60 50 40

30 20 10 0 1 3 5 7 9 11 13 15 17 19 21 23 25 27 29 31 33 35 37 39 41 43 45 47 Time (30 Minutes)

2020 Wet period Week Day 3000 2500 2000

1000 500 0 0:00 1:00 2:00 3:00 4:00 5:00 6:00 7:00 8:00 9:00 10:00 11:00 12:00 13:00 14:00 15:00 16:00 17:00 18:00 19:00 20:00 21:00 22:00 23:00

MW

1500

Time (30 Minutes)

Biomass Total wind Curtailment requirement Demand

Minihydro Total soalr PSPP Pump PSPP Generation

Curtailment 2020, Wet period Week Day Curtailment‌ 180 160 140

MW

120

100 80 60 40 20 0 1 3 5 7 9 11 13 15 17 19 21 23 25 27 29 31 33 35 37 39 41 43 45 47

Time (30 Minutes)

2020 Wet period Weekend 3000 2500 2000

1000 500 0 0:00 1:00 2:00 3:00 4:00 5:00 6:00 7:00 8:00 9:00 10:00 11:00 12:00 13:00 14:00 15:00 16:00 17:00 18:00 19:00 20:00 21:00 22:00 23:00

MW

1500

Time (30 Minutes) Curtailment requirement Total wind Biomass Demand

Total soalr Minihydro PSPP Pump PSPP Generation

Curtailment, 2020 Wet period Weekend Curtailment requirement

160 140 120 MW

100 80 60 40 20

0 1 3 5 7 9 11 13 15 17 19 21 23 25 27 29 31 33 35 37 39 41 43 45 47 Time (30 Minutes)

2025 High Wind period Week Day 4000 3500 3000

2500

1500 1000 500

Time (30 Minutes) Biomass Total wind Curtailment requirement Demand

Minihydro Total soalr PSPP Pump PSPP Generation

23:00

22:00

21:00

20:00

19:00

18:00

17:00

16:00

15:00

14:00

13:00

12:00

11:00

10:00

9:00

8:00

7:00

6:00

5:00

4:00

3:00

2:00

1:00

0

0:00

MW

2000

2025 High Wind period Week Day Curtailment of VRE Curtailment requirement 450 400 350

MW

300 250 200 150 100 50 0 1 3 5 7 9 11 13 15 17 19 21 23 25 27 29 31 33 35 37 39 41 43 45 47 Time (30 Minutes)

2025 High Wind period Week End Curtailment requirement Total soalr

3500

2500

Total wind

2000

Minihydro

1500

Biomass

1000 PSPP Pump 500 Demand

0

0:00 1:30 3:00 4:30 6:00 7:30 9:00 10:30 12:00 13:30 15:00 16:30 18:00 19:30 21:00 22:30

MW

3000

Time (30 Minutes)

PSPP Generation

2025 High Wind period Weekend Curtailment requirement

350 300

MW

250 200

150 100 50 0 1 3 5 7 9 11 13 15 17 19 21 23 25 27 29 31 33 35 37 39 41 43 45 47 Time (30 Minutes)

2025 High Wind period Week Day Without future Pump Storage Development Curtailment requirement Total soalr

4000 3500 3000

Total wind

Minihydro 2000

Biomass

1500

PSPP Pump

1000 500

Demand

Time (30 Minutes)

22:30

21:00

19:30

18:00

16:30

15:00

13:30

12:00

10:30

9:00

7:30

6:00

4:30

3:00

1:30

0 0:00

MW

2500

PSPP Generation

2025 High Wind period Week Day Without future Pump Storage Development Curtailment requirement

500

450 400

MW

350 300 250 200 150 100 50

0 1 3 5 7 9 11 13 15 17 19 21 23 25 27 29 31 33 35 37 39 41 43 45 47

Time (30 Minutes)

2025 High Wind period Week End Without future Pump Storage Development

3000

Curtailment requirement Total soalr

2500

Total wind

2000

Minihydro

1500

Biomass

1000

PSPP Pump 500

Demand

Time (30 Minutes)

22:30

21:00

19:30

18:00

16:30

15:00

13:30

12:00

10:30

9:00

7:30

6:00

4:30

3:00

1:30

0 0:00

MW

3500

PSPP Generation

2025 High Wind period Week End Without future Pump Storage Development Curtailment requirement 450 400 350

MW

300 250 200 150 100 50

0 1 3 5 7 9 11 13 15 17 19 21 23 25 27 29 31 33 35 37 39 41 43 45 47

Time (30 Minutes)

Main Observations of NCP simulation results  No renewable energy curtailments are observed in dry periods.  Curtailments can be observed on High wind period from 2020 onwards.  Reduced curtailments can be observed in wet periods compared to high wind period.  Weekend days have higher curtailment levels at day time than week days where the demand is relatively high.  Off peak curtailment is significant in the lowest off-peak of the week which usually occurs on Mondays.  Both off-peak and daytime curtailments can be observed in high wind periods.  Introduction of pump storage units gradually decreases the curtailment requirement after 2025.  Curtailment requirement increases in the case where no pump hydro and coal development is considered in 2025 high wind period with 50% the minimum load operation of future combined cycle power plants. However the curtailment is reduced when the combined cycle plants are operated with 30% minimum load restriction.  Curtailment requirement is very low with the introduction of 600MW pump storage power plant in the year 2028.

Year

2020

None

None

150MW None

80 MW 50 MW

170MW None

140MW None

2022

None

None

220MW None

140MW 100MW

None

None

2025

None

None

380MW None

330MW 280MW

70MW None

20MW None

-

70MW None

30MW 111MW

-

-

2028

1.

1.

Maximum VRE Curtailment Requirement Dry Period High Wind Period Wet period (Jan-Apr) (May-Aug) (Sep-Dec) Weekday Weekend Weekday Weekend Weekday Weekend -Off-peak -Off-peak -Off-peak -Off-peak -Off-peak -Off-peak -Daytime - Daytime - Daytime - Daytime - Daytime - Daytime Case 1: With Future Coal Power, LNG and Pump Storage Development

-

Case 2: With No Future Pump Storage and Coal Power Development With new combined cycle minimum load operation constraint at 50% 2025

None

None

445MW None

380MW 430MW

None

None

2028

None

None

80MW None

200MW 276MW

None

None

175MW 160MW

None

None

With new combined cycle minimum load operation constraint at 30% 2025

None

None

215MW None

*Shadowed cells indicate that one or more coal units are under maintenance in the considered month of the period.

Transmission Network Study

Transmission Network Study  To evaluate the potential impacts of intermittent resources on the transmission grid  To define a planning process by which conventional and renewable resources can be accommodated

 To identify anticipated transmission congestion locations  To evaluate transmission and other grid improvements required to integrate NCRE sources

Classification of Power System Stability

Source : Power System Stability and Control by Kundur Prabha

 The objective of the stability analysis is to assess the system stability following a major disturbance (e.g. three- or single-phase fault or power plant/load rejection). The studies are carried out to analyze  The transient frequency variations  Voltage variations  synchronous generator rotor angle variation for stability.  In general, transient studies are carried out for a few second (10 sec).  These studies require detailed dynamic models of the generators, loads, tap changing transformers, HVDC lines, and Flexible AC Transmission System (FACTS) devices like STATCOM.  The non-linearities of such devices have to be accurately modeled in order to reflect transient behavior of the system.

 In case of Solar PV, the output power variations due to cloud cover are in the range of a few minutes to 10 minutes depending on the size of the solar PV plant.  Therefore short term frequency stability study has to be carried to see the limitation of PV capacities under steady state operating condition..

System Regulation Requirement due to intermittence based generation 10 9 8

Power Output (MW)

7 6 5 4 3 2 1 0 5:31:12 AM

7:55:12 AM

10:19:12 AM

12:43:12 PM

3:07:12 PM

5:31:12 PM

Power Output Variation of 10 MW Solar PV Plant (1sec data)

800

8000

700

7000

600

6000

500

5000

400

4000

300

3000

200

2000

100

1000 0

0

Time (min) T1

T2

T3

T4

T5

T6

T7

T8

T9

T10

Individual turbine output and total 10 MW wind farm output

Total

Total Power Output (kW)

9000

0 60 120 180 240 300 360 420 480 540 600 660 720 780 840 900 960 1020 1080 1140 1200 1260 1320 1380

Power Output (kW)

900

Impact of Intermittency of VRE (Data resolution)

Power output variation in a day of 650 kW Hambantota plant (1sec data)

Enlarged view of Fig. above for the time period 10.00 hrs. To 10.50 hrs

Power output variation in a day of 10 MW Hambantota plant

Enlarged view of Fig. 6.4 for the time period 10.30 hrs to 13.00 hrs

Week day, Week end and Daily Solar PV power variation

Spinning Reserve Requirement  Present policy is to keep 5% of the demand as the spinning reserve  Required capacity in each year for 5% spinning reserve

Peak Demand (MW) Spinning Reserve (MW)

2016 2483

2018 2020 2022 2788 3131 3394

2024 3681

2026 4014

2028 4398

124

139

184

201

220

157

170

 Spinning reserve required for load variability using the method adopted by Mid-West System operator in USA Peak Demand (MW) Sinning reserve for catering load variability (MW)

2016 2483

2018 2788

2020 3131

2022 3394

2024 3681

2026 4014

2028 4398

73

79

85

88

91

92

98

 10% of VRE capacity is taken as additional reserve requirement to cater for intermittency

Effect of solar ramp rate and short term frequency stability  The output power of solar PV plant will vary with cloud cover as given  The power could be either ramp down or ramp up with the movement of the cloud over the solar

 It is clear that ramp rate will vary randomly and cannot be accurately simulated.  The International Energy Agency (IEA) study has shown that the solar ramp rate depends on following factors.  Geographical spread  Time scale:  Weather patterns:

Output Power Variation of 10 MW Saga Solar PV plant in Hambantota on 30-11-2016

4.00 3.32

-2.00 -3.00

-1.33

-1.34 -2.06 -1.99

-1.84

Time

Power Ramp up and Ramp down of “Saga Solar PV plant” on 4-12-2016

2:50:51 PM

1:05:25 PM

12:46:56 PM

12:10:54 PM

11:52:25 AM

11:24:51 AM

10:26:35 AM

-0.82

10:20:19 AM

-0.74

10:02:27 AM

0.83

9:40:22 AM

9:25:39 AM

9:20:00 AM

1.00

-1.00

1.23

1.00

9:58:42 AM

1.13

0.00

1.94

1.85

2.00

9:10:55 AM

Ramp Rate (MW/min)

3.00

Land requirement and time taken to pass a cloud Capacity (MW)

Time to pass a cloud with Area requirement (km2) a speed of 25 km/h (min)

10

0.2025 (50 acres)

1.1

20

0.4050 (100 acres)

1.5

30

0.6075 (150 acres)

1.9

50

1.0125 (250 acres)

2.4

Poonarin

Potential Sites for Solar PV Plant Development

Sri Lanka Present Transmission Network

Cases Studied For Each Year • Year 2018 – – – – –

Case 1: Swing machine is only used for free governor Case 2: Swing machine + GT7 used for free governor Case 3: Swing machine + KCCP used for free governor Case 4: With All Hydro Governor (Victoria, Kotmale, Upper Kotmale, N’Lax) Case 5: Swing machine + KCCP + GT7 + 2x35MW GTs used for free governor

• Year 2020 – Case 1: With All Hydro Governor (Victoria, Kotmale, Upper Kotmale, N’Lax) used for free governor – Case 2: Swing machine + KCCP + GT7 used for free governor – Case 3: Swing machine + KCCP + GT7 + LNG used for free governor – Case 4: Swing machine + KCCP + GT7 + LNG + 2x35MW GTs used for free governor

• Year 2022, 2025, 2028, 2031, 2036 – LNG + GTs + Hydro (Victoria, Kothmale, Upper Kothmale)

Solar ramp rates used for the study Solar Power Ramps 11

10

9

8

7

6

5

4

3 0

25

50

75

Time (seconds) b c d e f g

Normal Ramp g b c d e f

High Ramp

100

Analysis for the year 2018- Case 1, only swing machine used in free governor mode Renewable Energy Type Wind Dendro Mini Hydropower Solar

Capacity (MW)

Amount dispatched

246 39 329 117

100% 100% 10% 100%

Capacity (MW) Distributed Solar Plants Solar Hambantota 30 Vavuniya 10 Polonnaruwa 10 10 Valachchenai Mahiyangana 10 10 Monaragala 10 Vavunativu 7 Habarana 10 Anuradhapur 5 a Kilinochchi 5 Sub Total 60 57 Grand Total 117 Grid Substation

Ramp Fast varying Nominal Nominal Nominal Nominal Nominal Nominal Nominal Nominal Nominal

Solar power capacities with their locations

Total Solar Power Variation(MW) 120

115

110

105

100

95

90

85

80 0

5

10

15

20

25

30

35

40

45

50

55

60

65

70

75

80

85

90

95

100

Time (seconds) b c d e f g

100*((3*A)+(3*E)+(4*B)+(2*C)+D) : VicGovonlyHamb30other30and57SD

Effective solar ramp rate considered for 117 MW solar PV capacity

System Frequency Response 50.25 50.2 50.15 50.1 50.05 50 49.95 49.9 49.85 49.8 49.75 49.7 49.65 49.6 49.55 49.5 0

25

50

75

100

125

150

175

Time (seconds) b c d e f g

With 57MW Distributed Solar g b c d e f

With 60MW Distributed Solar g b c d e f

With 58MW Distributed Solar

Frequency variation for the solar ramp given above

200

Victoria swing bus power response for the solar power ramp Victoria(Swing Bus) Power Variation 27.5 25 22.5 20 17.5 15 12.5 10 7.5 5 2.5 0

25

50

75

100

125

150

Time (seconds) b c d e f g

100*A : VicGovonlyHamb30other30and57SD

175

200

Analysis for the year 2018- Case 2, Victoria+GT7 in the free governor mode

Grid Substation Hambantota Vavuniya Polonnaruwa Valachchenai Mahiyangana Monaragala Vavunativu Habarana Anuradhapura Kilinochchi Sub Total Grand Total

Capacity (MW) Distributed Solar Plants Solar 30 20 20 10 20 10 10 10 10 10 10 10 5 5 120 60 180

Ramp Fast varying Nominal Nominal Nominal Nominal Nominal Nominal Nominal Nominal Nominal

Effective solar ramp rate for 180 MW solar PV capacity Total Solar Power Variation (180MW) 210 200 190 180 170 160 150 140 130 120 110 0

5

10

15

20

25

30

35

40

45

50

55

60

65

70

Time (seconds) b c d e f g

DP_TM_2018_study 4_Case 2_Solar180

75

80

85

90

95

100

Frequency Response for different solar PV capacities Frequency Variation 50.2

50.1

50

49.9

49.8

49.7

49.6

49.5 0

5

10

15

20

25

30

35

40

45

50

55

60

65

70

75

80

85

90

Time (seconds) g b c d e f b c d e f g b c d e f g

g b c d e f DP_TM_2018_study 4_Case 2_Solar150 g b c d e f DP_TM_2018_study 4_Case 2_Solar180 g b c d e f DP_TM_2018_study 4_Case 2_Solar90

DP_TM_2018_study 4_Case 2_Solar120 DP_TM_2018_study 4_Case 2_Solar170 DP_TM_2018_study 4_Case 2_Solar190

95

100

GT7 Power Variation 120 115 110 105 100 95 90 85 80 75 70 0

5

10

15

20

25

30

35

40

45

50

55

60

65

70

75

80

85

90

95

Time (seconds) b c d e f g

DP_TM_2018_study 4_Case 2_Solar180

Power response of GT7 for solar PV ramp given

100

Victoria Power Variation 30 27.5 25 22.5 20 17.5 15 12.5 10 7.5 5 2.5 0

5

10

15

20

25

30

35

40

45

50

55

60

65

70

75

80

85

90

Time (seconds) b c d e f g

DP_TM_2018_study 4_Case 2_Solar180

Victoria swing bus power response for the solar power ramp

95

100

Analysis for the year 2018-Case 4 Hydro Generators, Victoria, Kothmale, Upper Kothmale & and New Laxapana in the free governor mode Total Solar Power Variation (290 MW) 325

300

275

250

225

200

175

0

5

10

15

20

25

30

35

40

45

50

55

60

65

70

75

80

85

90

Time (seconds) b c d e f g

DP_TM_2018_study 4_Case 4_Solar290

Effective solar ramp rate for 290 MW solar PV capacity

95

100

Capacity (MW)

Solar Plants

Distributed Solar

Hambantota

30

-

Vavuniya Polonnaruwa Valachchenai Mahiyangana Monaragala Vavunativu Habarana Anuradhapura Kilinochchi Ampara Mannar Embilipitiya Trinco Sub Total Grand Total

20 20 20 10 20 20 10 20 20 20 20 230

10 10 10 10 10 5 5 60

Grid Substation

290

Ramp Fast varying Nominal Nominal Nominal Nominal Nominal Nominal Nominal Nominal Nominal Nominal Nominal Nominal Nominal

Frequency Response 50.3 50.2 50.1 50 49.9 49.8 49.7 49.6 49.5 0

5

10

15

20

25

30

35

40

45

50

55

60

65

70

75

80

85

90

Time (seconds) g b c d e f b c d e f g b c d e f g

DP_TM_2018_study 4_Case 4_Solar150 f g b c d e DP_TM_2018_study 4_Case 4_Solar210 g b c d e f

DP_TM_2018_study 4_Case 4_Solar180

DP_TM_2018_study 4_Case 4_Solar290 g b c d e f

DP_TM_2018_study 4_Case 4_Solar300

DP_TM_2018_study 4_Case 4_Solar240

Frequency Response for different solar PV capacities

95

100

Victoria Power Variation 37.5 35 32.5 30 27.5 25 22.5 20 17.5 15 12.5 0

5

10

15

20

25

30

35

40

45

50

55

60

65

70

75

80

85

90

95

100

Time (seconds) b c d e f g

DP_TM_2018_study 4_Case 4_Solar290

Victoria swing bus power response for the solar power ramp Hydro Governor Power Variation 80

70

60

50

40

30

20

10

0 0

5

10

15

20

25

30

35

40

45

50

55

60

65

70

75

80

85

90

95

100

Time (seconds) b c d e f g

Victoria

b c d e f g

Kothmale

b c d e f g

Upper Kothmale g b c d e f

New Laxapana

Power response of all hydropower plants in droop mode

Summary of Short Term Frequency Stability analysis Year

Scenario

Capacity

Victoria only

117 MW

Victoria + GT7

180 MW

Victoria + KCCP

210 MW

All Hydro Generators (Victoria, Kothmale, Upper Kothmale and New Laxpana)

290 MW

Victoria + KCCP+GT7+ 2x35MW GTs

300 MW

Victoria + Hydro (Kothmale, Upper Kothmale, New Laxapana)

302 MW

Victoria + KCCP + GT7

272 MW

Victoria + KCCP + GT7 + LNG

522 MW

Victoria + KCCP + GT7 + LNG + 3x35MW GT

582 MW

2022

LNG + GTs + Hydro (Victoria, Kothmale, Upper Kothmale)

540 MW

2025

LNG + GTs + Hydro (Victoria, Kothmale, Upper Kothmale)

730 MW

2028

LNG + GTs + Hydro (Victoria, Kothmale, Upper Kothmale)

940 MW

2018

2020

Contingency Analysis

Contingency simulations have been carried out for following case in 2020, 2025 and 2028.  When the frequency is at minimum due to the solar ramp, a three phase fault occur at Norochcholai 220 kV busbar and the fault is cleared after 6 cycles.  Further one unit of Norochcholai tripped after fault is cleared.

Frequency response for the contingency *simulation given above in 2020 Frequency Variation 50.2 50.1 50 49.9 49.8 49.7 49.6 49.5 49.4 49.3 49.2 49.1 49 48.9 48.8 48.7 48.6 48.5 48.4 48.3 0

5

10

15

20

25

30

35

40

45

50

55

60

65

70

75

80

85

90

95

100

Time (seconds) b c d e f g

60MW Solar Park + 242MW Solar Plants -Fault at 27.2 sec

Fault occurred at 27.2 sec and it was cleared after 0.12 sec (at 27.32 sec). Unit 3 (275 MW) tripped at just after fault is cleared. It was noticed that about 271 MW of load was shed to bring the frequency to stability limit.

Voltage Variation 1.2 1.1 1 0.9 0.8 0.7 0.6 0.5 0.4 0.3 0.2 0

25

Time (seconds) g b c d e f b c d e f g b c d e f g b c d e f g

633 - VOLT 2230 [VICTO-2

220.00] : 60MW + 70MW + 172W Fault at 27.2 sec

655 - VOLT 2560 [PANNI-2

220.00] : 60MW + 70MW + 172W Fault at 27.2 sec

665 - VOLT 2705 [NEWANU-2 653 - VOLT 2400 [HAMBA-2

220.00] : 60MW + 70MW + 172W Fault at 27.2 sec 220.00] : 60MW + 70MW + 172W Fault at 27.2 sec

220 kV busbar voltages at different busbars due to the three phase fault at Norochcholai 220 kV bus

50

Power Variation at Puttalam Coal Unit 1 and 2 600

500

400

300

200

100

0 0

5

10

15

20

25

30

35

40

45

50

Time (seconds) b c d e f g

Unit 1 g b c d e f

Unit 2

: Power swing at Norochcholai generators Hydro Power Plant Power Variation 80 70 60 50 40 30 20 10 0 -10 -20 0

5

10

15

20

25

30

35

40

45

50

55

60

65

70

75

80

85

Time (seconds) b c d e f g

Victoria

b c d e f g

Upper Kotmale g b c d e f

Kotmale

b c d e f g

New laxapana

Power swing at hydropower plants

90

95

100

Summary of the contingency simulation study

Scenario

State

Hydro Maximum Day Peak – DH

System Stable with Load Shedding

Thermal Maximum Day Peak - DT

System Stable with Load Shedding

Minimum VRE Day Peak – VRE_DP

System Stable

Hydro Maximum Night Peak - NH

System Stable with Load Shedding

Thermal Maximum Night Peak - NT

System Stable

Minimum VRE Night Peak – VRE_NP

System Stable

Hydro Maximum Off Peak - HMOP

System Stable with Load Shedding

Thermal Maximum Off Peak - TMOP

System Stable

PROJECTED DEVELOPMENT OF OTHER RENEWABLE ENERGY Year

2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037

Cumulative Cumulative Cumulative Mini hydro Wind Biomass Capacity (MW) Capacity Capacity (MW) (MW) 344 144 39 359 194 44 374 414 49 384 489 54 394 539 59 404 599 64 414 644 69 424 729 74 434 729 79 444 754 84 454 799 89 464 824 94 474 894 99 484 929 104 494 974 104 504 1044 109 514 1114 109 524 1184 114 534 1279 114 544 1349 119

As per Draft LTGEP 2018-2037

Cumulative Solar Capacity (MW) 210 305 410 465 471 526 581 685 740 795 900 954 1009 1064 1119 1173 1229 1283 1338 1442

Cumulative Total ORE Capacity (MW) 737 902 1246 1392 1463 1592 1708 1912 1982 2076 2242 2336 2476 2580 2691 2830 2965 3105 3265 3454

Annual Total ORE Generation (GWh) 2103 2471 3402 3784 4022 4338 4620 5084 5229 5447 5796 6014 6365 6601 6844 7193 7509 7860 8252 8670

Share of ORE from Total Generation % 13.0% 14.3% 18.4% 19.5% 19.8% 20.3% 20.6% 21.6% 21.2% 21.0% 21.3% 21.1% 21.2% 21.1% 20.9% 21.1% 21.1% 21.2% 21.4% 21.5% 96

Levelized Cost of Renewable Energy (Except Major Hydro) Renewable Technology and Typical Plant Factor Solar PV (at 17% PF) - 1412 USD/kW Capital Cost (2017-2020) -1100 USD/kW Capital Cost (2021-2025) -900 USD/kW Capital Cost (2026 onwards) Wind (at 35% PF) Mini Hydro (at 37% PF) Biomass (at 80% PF)

Components of Levelized Cost (USCts/kWh) Capacity O&M Total Levelized Fuel Component Component Component Cost (UScts/kWh) 11.14

0.66

-

11.80

8.68

0.66

-

9.34

7.10

0.66

-

7.76

7.26 6.22 3.44

0.93 1.59 5.76

8.99

8.19 7.80 18.19

SCENARIO 1 2 3 4 5

6

Victoria+KCCP for Regulation reserve All Hydro Generators for Regulation reserve (Vic, Kot, Upp Kot & New Lax) LNG+GTs+HYDRO for Regulation reserve PSPP development included LNG+GTs+HYDRO for Regulation reserve PSPP and Coal power development excluded LNG+GTs+HYDRO for Regulation reserve PSPP included and Coal development excluded LNG+GTs+HYDRO for Regulation reserve LNG Development only in the Western Region Reference Case

PV Cost up to 2036 (USD million)

Difference with Scenario 3 (USD million)

12,979

(118)

12,993

(104)

13,097

-

13,653

556

13,618

521

12,872

(225)

12,382

(715)

Difference of PV Cost for Each Scenario Compared with Scenario 3 800

556

Difference(USD Millions)

600

521

400 200

0

0 -200

(118)

(104)

(225)

-400 -600 -800

(715) Scenario 1 Scenario 2 Scenario 3 Scenario 4 Scenario 5 Scenario 6 Reference

RECOMMENDATIONS  Day ahead, hourly basis and accurate Wind and Solar PV energy forecasting system should be implemented as early as possible. This should be implemented before the commissioning of 100 MW wind farm in Mannar and 100 MW solar park in Monaragala.  24 hour (round the clock), renewable energy desk has to be set up at new system control center and output from each renewable energy sources have to be monitored (if existing plants are not equipped with communication facilities, measures have to be taken for establishing them).  In order for smooth operation of power system, VRE curtailment rights have to be given to system operator. A compensation mechanism has to be included in PPA of future VRE plants.  All future conventional plants including IPPs have to be procured for running on free governor mode (2%-5% droop) when they are on the system for dispatching.

RECOMMENDATIONS…  All conventional generators must be procured with dynamic simulation models compatible for PSCAD, PSS/E and DigSilent. The parameters of these models have to be tuned for site condition of the place that they are located.  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 plan in line with Long Term Generation Expansion Plan (once in two years).  Planned network strengthening projects must be completed as scheduled.  Future coal plants should be developed based on Advanced Subcritical basis and could be able to de-load the plant up to 35% in order to keep the VRE curtailment at a minimum level.  It was noted that increase of penetration level of RE sources leads to increase in unit cost of generation. Thus this variation should be reflected in the tariff set in future.

THANK YOU

Sri Lanka Present Transmission Network

Study Methodology Renewable Energy Resource Estimation and Projection Major Hydro, Mini Hydro, Wind , Solar, Biomass Long Term Generation Expansion Planning System Studies •Operational Study ( Long Term and Short Term) •Transmission Network Study ( Steady State and Transient Stability) •Economic Analysis

• • • •

Results and Analysis Identification of System Operational limitations Identification of impact on System Stability Renewable Energy Curtailment Requirement Determination of of Cost Implications 104

Scenario

Description

Regulation RE Projection Reserve Option

Reference Scenario

Only existing ORE plants at 1st September 2016 were included and no future development considered.

Only the existing and committed ORE

Scenario 1:

Victoria and Kelanitissa Combined Cycle Plant are the only generators allocated to absorb Solar and Wind vitiations which operate on frequency control mode. Solar integration is limited.

Revision 1

Option 1

Scenario 2:

All hydro generators capable of frequency regulation (Vict, Kot, Upp Kot & New Lax) will be operating on frequency control mode. Solar integration is limited.

Revision 1

Option 2

Scenario 3:

All the converted & future LNG combined cycle power plants, gas turbine plants and all hydro generators capable of frequency regulation would be operating on frequency control mode.

Revision 1

Option 3

Scenario 4:

The development of future Coal Power Plants and the Pumped Storage Power Plant (PSPP) were excluded from the optimized expansion plan.

Revision 2

Option 3

Scenario 5:

The development of the future coal plants was excluded from the plant schedule and the development of pump storage power plant was included.

Revision 1

Option 3

Scenario 6:

Future Coal power and pump storage development is included and the development of the future LNG plants was limited to 5 plants in the Western Region only.

Revision 1

Option 3

-