1

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1. Input Parameters For The Long Term Generation Expansion Plan 2018-2037

In the process of preparing Long Term Generation Expansion Plan 2018-2037, Draft Generation Planning Code under the Grid Code issued by the Transm is si on Licensee based on the PUCSL Grid Code issued in May 2012, "Sri Lanka Energy Sector Development Plan" issued by the Ministry of Power and Energy and General Policy Guideline is s ued in June 2009 by PUCSL are bei1ig followed as general guidelines.

(J'he following input data is still in the provisional status and data could be subjected to revisions/updates in the verification process of formulating the Long Term Generation Expansion Plan.)

I. Planning Period: 20 Years (2018-2037)

2. Study Period: 25 Years (2018-2042)

3. Planning Criteria:

3.1 Loss of Load Probability: Maximum 1.5%

3.2 Reserve Margin: Maximum 20%

Minimum 2.5%

4. Economic Parameters

4.1 Reference Date for the costs: 01st January 2017

4.2 Exchange Rate: LKR 148.88/USD (Monthly average as at O 1 st Januar y 2017)

4.3 Discount Rate: l0%

4.4 Cost of Unserved Energy: USD 0.663/kWh

4.5 Social Damage Cost: Damage costs would be determine d usmg an breakeven ana lys is with comparison to latest available studies

2

2. Base Dem:md Forecast 2018-2042

Bflse Lofld Forecflst 2018 -2042

Year

Demand *Net Loss Generation Peak

(GWh) (%) (GWh) (MW) t / \/ rt 2017 . { ,IF · ri;;.,"' ;. 1..., '136 86 ' ' ·9,92' l ' · 1'5f60

I< ' 2585 ' IO

2018 14588 9.88 1 6 18 8 2738 2019 15583 9.84 17285 2903 2020 16646 9.81 18456 3077 2021 1 74 78 9.77 19370 3208 2022 18353 9.73 20331 3346 2023 19273 9.69 21342 3491 2024 20242 9.65 22404 3643 2025 l l 260 9.61 23522 3804 2026 22332 9.58 24697 3972 2027 23459 9.54 25933 41 4 9 2028 24639 9.50 27225 4335 2029 25867 9.46 28570 4527

2030** 271 64 9.42 29990 4726 2031 28388 9.38 31 3 28 4939 2032 29637 9.35 32692 5157 2033 30926 9.31 340 99 5381 2034 32251 9.27 35546 5612 2035 33642 9.23 37063 5854 2036 35090 9. 19 38642 6107 2037 3661 3 9 . 15 40302 6372 2038 38165 9.12 419 92 6642 2039 397. 33 9.08 43699 6915 2040 413 24 9.04 45431 719 3 2041 42967 9.02 47227 7481 2042 44700 9.00 49121 7 784

5 Year Average Growth (2018-2022) 5.9%

5.9% 5.1 %

10 Year Average Growth (201 8 - 2027) 5.4%

5.4% 4.7%

20 Year Ave rage Growth (20 I 8-2037) 5.0%

4.9% 4.5%

25 Year Average Growth (2018-2042) 4.8%

4.7% 4.4%

*Net lo ss include the los ses at Transmission and Dis tribution lev e ls * *It is ex pected that day peak would exceed the nig ht pea k from th is year onwards.

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Oil

Oil

Oil

3. Existing and Committed Thermal Power Plants

3.1 1 Ex is ting CEB Owned Power Plants

Diesel 2019

Res idua l 2024 Oil Residual

2023 & 2025

Auto 2023 Diesel Naphtha 2033

Coal

Furnace Oil

Furnace Oif·

3.2 Existing Independent Power Producers (IPPs)

*Subjected to Cabinet approval.

Residua l 20 18 Oil

Furnace 2020 Oil Furnace 2018*

Furnace 2035

Auto Diesel

2025

2023

Kelanitissa Small GT 4 80 16.3

2 Sapugaskanda Diesel A 4 80 17.4

3 Sapugaskanda Dies el B 8 80 8.7

4 Kelanitissa GT7

115 113

5 Kelanitissa Combined Cycle- ' 165 161

6 Lakvijaya Coal Power Plant 3 900 275

7 Uthuru Janani 3 26.7 8.67

8 Bat·ge Mounted Pwo er Plant 4 60 15

Asia Power 8 51 6.35

2 Northern Power 6 38 5

3 ACE Powe r Embilipitiya 13 100 7.1

4 West Coast Combined.Cycle

300 270

5 Sojitz Combin ed Cycle

16 3 163

4

3.3 Commi tted Therma l Power Plants

LNG Combined Cycle

2 f'urnace Oil based T herma l Power Plant

3 Kelaniti ssa Gas Turbin es 3

300

170

35

Natural Gas

Furnace Oil

Auto Diesel

Other parameters used in modelling the thermal power plants are prese nted in Annex I .

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4. Existing and Committed Hydro Power Plants

4.1 Existing Hydro Power Plants

UpperKothmale 2 75 150 409 2.5 0.8 · 473.1

Victoria 3 70 210 865 722 688 190

Kothmale 3 67 201 498 174 154 20 1.5

Randenigala 2 61 122 454 861 •. '558 77.8 Ukuwe la 2 1 8.5 37 154 4.1 2.1 74.98

• Bowathenna 40 40 48 56.01 36.53 52

Rantambe 2 24.5 49 239 21 4.4 32.7

Flash Boards)

Laxapana Complex

Canyo n 2· 30 60 160 11 5.7 108 .8 192 .7

54 (Without 47,938

Wimalas llre ndra 2 ' 25 50 112 Flash Boards) 225 6 Old Laxapana

3

9.6

28.8

59,6(With 53.583

286 0.395 0.245 472.4

2 12.5 25

New Laxapana 2 58 116 552 0.925 0.629 541

Pol pitiya 2 43.5 87 453 0.202 0.113 259! l .

Other Hydro

Samana la wewa 2 60 120 344 278 218 320

Kukule 2 37.5 75 300 5.65 1.67 186 .4

Udawalawa 3 2 6 268.7 187.6 14.3

1nginiyagala

2 2.475 4.95

949.8

844.94

27.13 2 3.15 6.3

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4.2 Committed Hydro Power Pla nts

Broadlands 2 17.5 35 126 0.216 0.198 56.9 2020 Moragolla 2 15.1 30.2 97.6 4.66 1.9 8 69 2022

5. Candidate Power Plants

5.1 Candidate Therma l Power Plants

Gas Turbine 35 Auto Diesel

2 Gas Turbine 105 AL!tO Diesel

3 Comb in ed Cycle 150 Auto Diesel

4 Combined Cycle 300 Auto Diese l

5 Combined Cycle 150 Natural Gas

6 Combin ed Cycle 300 Naturlll Gas

7 Furnace Oil based Thermal Power Plant 15 Furnace Oil

8 High Effici nt Coal Power Plant 300 Coal

9 Super Critic al Coal Power Plant 600 Coal

10 Nuclear Power Plant 600 Nuclear Fuel

1 1 Dendro Power Plant 5 Biomass

Other paramete rs and capit a l cost figures used in modell ing the ca ndidate thermal power plants are presented in Annex 2.

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5.2 Candidate Hydro Power Plants

Gin Gang!! 2 10 20 66 0.305 2022

Thal pitigala 2 7.5 15 5l.3 15.56 93 2020 Pumped Storage Power P lant

3 200 600

Capital cos t figu res used in mode.ll ing the ca ndidate hydro power plants are presented in Annex 2. -

6. Fuel Prices

Fuel prices used for the s tud ies are as follows.

lmtlOrted CIF Price

Delive red at Power Pla nt Price

Heat Content ( kCal/kg)

53. 1

101.5

10500

47.9

95 79.03

10880

85.4

10300

85.4

10300 * Oil prices are based on Ceylon Petroleum Corporat ion data (CPC) data.

Imported C IF P rice 72.9 66.8

Handlin g Charge 3.0 3.0

De live red at Power i>Jant P rice 75.9 69.8

Heat Content (kCa l/ kg) 6300 5900

. 7.5 2.5

10.0 13000

8

6,000 --- - - -- --- - -- --- - -- -- ----------------- - - -- -- ------ -------- --- -

Potential of Hydropower System

5,000

4,000 ..c 4050GWh 3:: <.!)3,000

-.- Annua l Tot al - Average 2,000 -

1,000

0 *rlq *M*W*f*fiN OO*rlq*OM*WffiN*O*Orlq OMW*f*fiN*O*O*r*q**O

""n-rr 1- n -r n ·n - ,n ·rr n - r"l'T TT r1 - r, Tr r r r r r, - n - rr n -1- rrr rrr r ,-rr rr TTir-r r n-n -r1-rr 1-rr r·rT r1- n T rrn-rl·n1rrrrr ri-r-TY T ,

rl rl rl rl N N N M M M q q q q w w w oo oo oo m m m o rl

7. Hydro Data

Potential of the major hydro system (Mahaweli, Laxapana and Samanala) has been eva luated using hydrological data from 1 979-2014. Foll o wing five hydro conditions with the specific probab ili ties would be used.

Very Wet Wet Medium Dry Very Dry Average

Month Energy Power Energy Power Energy Power Energy Power Energy Power Energy Power (GWh) (MW) (GWh) (MW) (GWh) (MW) (GWh) (MW) (GWh) (MW) (GWh) (MW)

Jan 300. l 890.6 299. l 897.l 293.6 884.5 293.2 880.4 287.2 802.5 295.0 882.9 Feb 241. 0 840.3 228.9 848.8 205.0 809.1 178.7 81 l .3 166 .7 775.4 207.5 818.8

Mar 261.4 845.5 233.8 830.3 215 .,3 794.7 180.5 · 772.6 157.8 696.9 21 5.5 798.7 Apr 268.5 802.6 246.0 788.4 225.7 75 l .O 199.9 691.2 198.9 641.1 228.8 749.2 May 418.4 858.8 399.0 856.8 333.6 835.3 280.0 808.8 299.9 801.3 345.4 836.3 Jun 464.2 978.7 450.9 .986.5 378.1 98 l.8 322.9 943.7 333.9 902.9 390.8 972.8

-

2015 and 2016 inflow data has been reques ted from Mahawe li Authority by the System Control Centre.

Jul 423.3 985.8 414.8· 976.3 348.4 899.7 316. 5 880.3 291.3 849.7 36 l.6 918.2 Aug 409.0 957.6 390.4 948.3 325.7 894.6 270.0 858.0 255.7 841.4 335. I 903.5

Sep 471.3 992.l 410.7 979.4 344.4 938.4 277.8 906.4 256.8 815.6 356.0 941.0 Oct 588.9 l 1 22 .3 514.9 l 117.7 463.8 1 07 5.6 388.0 103 3. l 344.7 940.8 469.2 1075.6

Nov 457.0 1 0 73.0 377.6 1 05 3.l 342.7 1022.8 298.6 993.9 262.3 9 l l. 4 350.5 102 4.0 Dec 531.1 1198 . 1 517.6 11 92.3 489.8 1178.9 483.1 l 168.7 408.3 1096.5 494.4 l 177.8

Total 4730.6 4320.4 3863.7 3525.5 3246.3 4049.8

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8. Renewable Energy Integration

To determine the optimum integration capacity of wind, solar, mini hydro and bio mass based generatio n to the system, currently a comprehensive Renewable Energy Inte gration Study is being carried out considering all the relevant generation and transmissio n constraints in in tegrating RE generation.

In this study, five main wind regimes were considered for the modelling purp ose, namely

};a, Mannar

};a, Puttalam

};a, Northern

};a, Eastern

};a, Hill Country

These regime s were selec te,d consi dering the measurement data availabilit y, capturin g the diversity of wind portfolios and increased wind development projection.

Solar irradiance measurements were obtained from two locations namely,

};a, Hambantota

};a, Kilinochchi

The Capital Costs of renewable energy technologies (except major hydro) would be considered as follows in the generation expansion studies:

./ Sola r: USO 1400/kW at the present context and would gradually declin e to USD 900/kW in 2025 and stabilize at that point.

./ Wind: USD 1525/kW

./ Biomass: USD 2067/kW

./ Mini Hydro: USO 1729/kW

The O & M Costs of these technologies a re con s idered as a pe rcentage of the capital costs and the percentages are as follows:

! 1.

9. Development of the Reference Case

According to PUCSL guidel ines, non-dispatchable plants already in operatio n by I st January 2017 shall be included in the reference case.

',' f f l!l { l \ • :HJ {n]i.r ·f' • >

11 t-., , 1 /l·f·, 1; •(.1 't. ' • ,],,. •" ,•1·1 Y>,,· "tc 1,

' • • • I • • 1r;i 1. >!,: i? 0'.tlW1rf " ' • '• J,, .!

Mini Hydro 3 Wind 1.5 Solar 0.7 Biomass 4

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10. Sensitivity Studies and Scenario Analysis

Apart from developing the Base Case Plan and the Reference Case, the foll o wingsensitivities and scenarios would be analyzed in the LTGEP:

./ Demand Forecast (High/Low)

./ Discount Rate (High/Low)

./ Fuel Price Fluctuations

./ Fuel Diversification Options

./ Energy Mix with the Introduction of Nuclear Power

./ Scenario with India-Sri Lanka HVDC Interconnection

Annex 1

Plant Noof Units

Plant Nameplate Capacity

(MW}

Maximum Generating capacity of a Unlt(MW)

Study Capacity (MW)

Forced Outage Rate (%)

Fullload Heat Rate (kcal/kWh)

Elf (%)

Fuel type M aintenance Days Per Year

Fixed O&M

($/kW per

month)

Variable O&M (US$/MWh)

Existing CEB Owned Power Plants

Kelaniti ssa CCY 1 165 165 161 8.4% 1850 46.5% Naphtha 30 2.06 3.01 Kelanitissa GT7 1 11 5 115 113 34.3% 2860 30.1% Auto Diesel 52 0.20 5.56 Kelanitissa Small GT 4 80 20 16.3 29.0% 4022 21.4% Auto Diesel 35 3.35 0.72 Sapug. Diesel A 4 80 20 17.4 11.1% 2246 38.3% Residu al Oi l so 9.35 6.34 Sapug. Diesel B 8 80 10 8.7 7.7% 2059 41.8% Residu al Oil 47 8.56 1.88 l akvijayaUnitl 1 300 300 275 14.0% 2489 35% Coal 52 1.70 3.15 lakvijaya Unit2 1 300 300 275 7.7% 2378 36% Coal 52 1.70 3.15 lakvijaya Unit3 1 300 300 275 11.8% 2378 36% Coal 52 1.70 3.15 Uthuru Janani 3 26.7 8.9 8.67 22.9% 2136 40.3% Furnace Oil 38 1.93 9.21 Barge Mounted Plant 4 60 15 15 4.9% 2210 38.9% Furnace Oil 58 5.40 11.03

Existing Independent Power Producers (IPPs)

Sojitz CCY 1 163 163 163 1.7% 1901 45.2% Auto Diesel 30 1.0 7 1.15 Westcoast CCY 1 300 270 270 8.0% 2247 38. 3% Furn ace Oil 60 2. 20 12.94 ACE Power E'pitiya 13 100 7.1 7.1 4.5% 2230 38.6% Furna ce Oil 59 0.29 10.17 Northern Power 6 30 s s 8. 0% 2217 38.8% Furn ace Oil so 1.27 26.47 Asia Power 8 50.8 6.35 6.35 0.1% 2222" 38. 7% Resid ua l Oi l 70 4.27 14.96

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Plant

Full Load

Max Study Heat

capacity Capacity FOR Rate

IMW) IMW) (%) (kcal/' kWh)

Elf. , HHV net. 1%)

Mal nt: Days P er

Year

Fixed O&M

IS/ kW per month)

Var iabl e O&M ! US$/ MWh)

Capital Cost

Construction Econ omic Fue l type

Pure With lDC

Pe riod (years )

Plant life ! Years)

Candidate Thermal Plants

Gas Turbine Gas Turbine Combined Cycle Combined Cycle High eff..Coal PP Super critica l Coal PP Combined Cvcle Comb ined Cvcle Nuclear Power Plant De ndro Plant ReciprocatingEngines

Annex 2

flltVnet. ($/ kW) 1$/ kW) 35 35 8.0% 3060 28.1 % Auto Diesel 30 0.69 5.52 737.8 785.9 1.5 20

105 105 8.0% 2857 30.1% Auto Diesel 30 0.52 4.14 501.8 534.5 1.5 20 150 144 8.0% 1842 "46.7% Auto Diesel 30 0.54 4.67 1469.9 1668.9 3.0 20 300 288 8.0% 1 785 48.2% Auto Diesel 30 0.41 3.52 1114.0 1264.8 3.0 30 300 270 3.0% 2241 38.4% Coa l 45 4.47 5.82 1786.2 2117.2 4.0 30 600 564 3.0% 2082 41.3% Coal 45 4.79 5.82 1916.8 2272.0 4.0 30 150 143.5 8.0% 1790 48.0% NG 30 0.25 4.97 1157.3 1314.0 3.0 30 300 286.9 8.0% 1793 48.0% NG 30 0.38 4.97 1114.9 1265.9 3.0 30 600 5 52 0.5% 2685 32.0% Nuclear 40 8.42 17.52 4594.7 5687.3 5.0 60 5 5 2.0% 5694 15.1% Biomass 74 2.43 44.60 1703.3 1814.2 1.5 30

15 15 5.0¾ 2210 38.9¾ Furnace Oil 60 2.38 6.34 950.0 1011.9 1.5 20

Plant

Capacity (MW)

Capi tal Cost

Constrict ion Period (years )

Economic Plant Life (Years) Pure

($/kW) WithlDC ($/kW)

Candidate llvdro Power Plants Seeth awaka 20 2087.9 2474.8 4.0 50 Gin Ganga• 20 13748.0 18579.1 3.5 so Tha lpitiga la ' 15 6960.0 8073.6 7.0 so Pumped Storage PP 600 1043.1 1291.2 5.0 50

*Both these project s are multipurposeschemes constructed mainly for water regulation and irr igation purposes.

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Annex 3

LNG PRICE

CIF- 7.5$/MMBtu (Based on 14 % of J_CC Prices)

Handling Cost - 2.5$/M MBtu

Total LNG Price = CIF Price+ Handling Charge = 10 $/M M Btu

Ter111iw 1l Co sts FSRUCosts

(MUSD) Termina l C o s t I Mtpa 488 Terminal C o s t 2 Mt1m upgrade 206 Fixed O&M pe r vear 2.1 Variable O&M oer vear 1.8

* Reco very o f Term in als at 2.5$/Mmbtu within 15 years.

* Recovery of FSRU unit at 2.5$/Mmbtu within 10 years.

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( MUSD)

FSRU CAP ITAL COST 170 FSRU COST Annual Cost 50