Energy Plc. Results of 212 21 February 213 1
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s Results Summary 3
Key P&L performance indicator for is Normalized Net Profit (NNP) IPP, GHECO-One and HHPC have outstanding loan in USD which will be repaid by USD linked and USD operating cash flows Under Thai GAAP the outstanding USD loan is converted at year-end to THB at the then current exchange rate. Any difference in THB outstanding loan amount due to using a different exchange rate compared to last year leads to an unrealized FX gain (THB appreciation) or loss (THB depreciation). Since the USD loans in IPP, GHECO-One and HHPC are served by USD linked cash flows the unrealized FX gains / losses should, in s view, be ignored from an economic point of view. s management has focused on core operational profit. Therefore, we consider NNP, net profit ignoring net unrealized FX gains / losses, as basis for dividend payment consideration. 4
FY-212 Key Factors affecting results Cogen Business: Industrial customer sales volume continued to increase while gas margin on industrial customer electricity sales has recovered back to almost normal level in H2-212. Industrial demand increased, despite BSTE explosion in May. 74 MW sales to EGAT, non-firm during March-May and firm from June 212 IC electricity sales margin is eased after adjustment +3 Satang in Jun and +18 Satang of Ft in Sep, while gas price continue to rise, from tightest level observed in May 212. Better optimization of Cogeneration fleet dispatching more from Phase 5 and CFB units, thanks to improved volume, whereas all CFB units had major maintenance in H2-212. SPP12 started commercial operation on 12-Dec-212. IPP Business: GIPP: performed scheduled major maintenance for around 1.5 months per unit in Q1-212 and minor inspection in Q4-212 after reaching CAH in December 212. GHECO-One: started commercial operation and contribution 19-Aug-212. HHPC: returned to normal operation with production in 212 of 542 GWh, compared to approximately 9 GWh in 211. 5
Financial Key Summary YoY Group (MTHB) 211 212 212 vs 211 % Revenue (1) 4,955 58,318 17,363 42.4% Gross Profit 12,433 17,223 4,79 38.5% EBITDA 9,954 13,7 3,116 31.3% Profit Before Tax 4,274 7,16 2,833 66.3% Tax 925 74 (221) -23.9% Net Profit 3,494 5,56 2,66 59.1% Normalised Net Profit 4,14 5,78 975 23.7% Key positive driver for 212, comparing YoY, is contribution from GHECO-One. Increasing IC sales volume and better utilization of Phase 5 and CFB units neutralized squeezed operating gas margin for first half of 212. Tax decreased mainly due to lower tax rate and contribution from newer units with BOI tax holdings. HHPC returning back to normal operations provides substantial variance YoY from operating loss in 211. Note: 1) Revenue from ordinary business excluding exchange gain / interest incomes / investment incomes. 6
Financial Key Summary - QoQ Group (MTHB) Q3-212 Q4-212 Q4-212 vs Q3-212 % Revenue (1) 15,69 17,233 1,624 1.4% Gross Profit 4,531 5,56 525 11.6% EBITDA 3,686 3,932 246 6.7% Profit Before Tax 2,478 2,45 (433) -17.5% Tax 252 18 (72) -28.5% Net Profit 1,885 1,579 (36) -16.2% Normalised Net Profit 1,492 1,486 (6) -.4% Key positive factor of Gross Profit and EBITDA for Q4-212, QoQ, is contribution from GHECO- One. However, the slight negative factor of NNP is mainly due to lower capacity payment of GIPP after reaching CAH and lower dispatch of HHPC in Q4-212. GIPP posted NNP 378 MTHB in Q3-212 and 267 MTHB in Q4-212. GHECO-One posted NNP 372 MTHB in Q3-212 and 631 MTHB in Q4-212. HHPC posted NNP 16 MTHB in Q3-212 and 6 MTHB in Q4-212. Note: 1) Revenue from ordinary business excluding exchange gain / interest incomes / investment incomes. 7
EBITDA & NNP by quarter from 211 212 EBITDA in MTHB 5, NNP in MTHB 2, 4, 3, 2, 1, 1,3 1,73 1,14 1,652 1,762 1,947 624 721 651 888 1,554 1,113 1,492 1,486 1,186 914 1,766 1,82 1,935 1,751 1,9322,1 1,448 417 1,5 1, 5 Q1-211 Q2-211 Q3-211 Q4-211 Q1-212 Q2-212 Q3-212 Q4-212 EBITDA - Cogen Business EBITDA - IPP Business NNP - Consolidated H2-212 results are mainly driven by contribution of GHECO-One and improved gas margin. Results of Cogen business is flat from Q3-212. 8
Cogen Business - YoY Cogen Business (1) IPP Business (2) Group Bt mn 211 212 change % 211 212 % 211 212 % Gross Operating Revenue (3) 29,97 38,26 8,929 3.7 12,17 2,45 69.8 4,955 58,318 42.4 Fuel Costs (Gas, Coal, Diesel, Biomass) 19,628 27,252 7,624 38.8 8,412 13,292 58. 28,4 4,543 44.6 Other Variable Costs(Water/Chemicals) 424 464 4 9.5 58 88 51.7 482 552 14.5 Gross Profit 9,45 1,39 1,265 14. 3,547 7,26 98.1 12,433 17,223 38.5 Maintenance & Other Operating Costs 2,129 2,857 728 34.2 438 1,48 221.4 2,479 4,153 67.5 EBITDA 6,916 7,452 537 7.8 3,19 5,617 8.7 9,954 13,7 31.3 Depreciation & Amortization 2,89 2,693 63 28.9 1,183 1,668 41. 3,272 4,36 33.2 Net Financial Cost (4) 1,315 1,451 136 1.3 42 938 133.2 1,553 2,265 45.8 T axes 494 397-97 -19.7 431 37-28.8 925 74-23.9 Minority Interest of Net Profit 146 (843) Minority Interest of Unrealised FX Gain/Loss (245) 18 Normalised Net Profit 3,17 2,912-16 -3.5 1,92 2,75 147.6 4,14 5,78 23.7 COGEN BUSINESS Industrial customer electricity sales volume increased by 9%, steam sale volume increased by 13%, and 74 MW new SPP sales started from March on non-firm basis and June for firm sales under PPA. Industrial sales volume increase mainly driven from new sales to GE Phase 5 customers and SPP11 contribution, despite loss of demand from BST group (1 MW and 125 ton/h) due to BSTE explosion in May. Ft increasing.3 THB/KWh in Jun-212 and.18 THB/kWh in Sep-212 brought gas operating margin closed to normal level despite the continue rising of gas price, while, on the other hand, steam margin increased in THB/ton terms. Note: 1) Cogen business includes operation of GE, SPP1, SPP2, SPP3, SPP11 and SPP12 2) IPP business consists of IPP, GHECO-One and HHPC 3) Excluding exchange gain / interest incomes / Investment Income 4) Net of interest incomes, interest expenses and financial related costs 9
IPP Business - YoY Cogen Business (1) IPP Business (2) Group Bt mn 211 212 % 211 212 change % 211 212 % Gross Operating Revenue (3) 29,97 38,26 3.7 12,17 2,45 8,388 69.8 4,955 58,318 42.4 Fuel Costs (Gas, Coal, Diesel, Biomass) 19,628 27,252 38.8 8,412 13,292 4,879 58. 28,4 4,543 44.6 Other Variable Costs(Water/Chemicals) 424 464 9.5 58 88 3 51.7 482 552 14.5 Gross Profit 9,45 1,39 14. 3,547 7,26 3,479 98.1 12,433 17,223 38.5 Maintenance & Other Operating Costs 2,129 2,857 34.2 438 1,48 97 221.4 2,479 4,153 67.5 EBITDA 6,916 7,452 7.8 3,19 5,617 2,59 8.7 9,954 13,7 31.3 Depreciation & Amortization 2,89 2,693 28.9 1,183 1,668 484 41. 3,272 4,36 33.2 Net Financial Cost (4) 1,315 1,451 1.3 42 938 536 133.2 1,553 2,265 45.8 T axes 494 397-19.7 431 37-124 -28.8 925 74-23.9 Minority Interest of Net Profit 146 (843) Minority Interest of Unrealised FX Gain/Loss (245) 18 Normalised Net Profit 3,17 2,912-3.5 1,92 2,75 1,613 147.6 4,14 5,78 23.7 IPP BUSINESS IPP reached contracted available hours and then performed minor maintenance. The result of 19 MTHB lower in EBITDA was mainly from less dispatched electricity due to major and minor maintenance. HHPC returned to normal operation resulting in higher EBITDA contribution of approximately 769 MTHB for the period. GHECO-One recorded DLD compensation from contractor in Q1-12 for 1,46 MTHB, expense on LD compensation to EGAT in Q2-12 for 618 MTHB and operational result contributed since19-aug-212. YTD EBITDA and NNP of GHECO-One is 2,3 and 1,386 MTHB, respectively. Note: 1) Cogen business includes operation of GE, SPP1, SPP2, SPP3, SPP11 and SPP12 2) IPP business consists of IPP, GHECO-One and HHPC 3) Excluding exchange gain / interest incomes/ Investment Income 4) Net of interest incomes interest expenses and financial related costs 1
Summary of Economic Indicators 211 212 % MW Contracted (EGAT + ICs) MW 2,194 (1) 3,6 39.5 TPH Contracted tph 1,9 (1) 1,5 4.1 EGAT IPP business GWh 4,93 (2) 7,23 46.1 EGAT SPP business GWh 4,49 5,11 23.8 Industrial Customer GWh electricity sold GWh 4,249 4,64 9.2 Industrial Customer kton steam sold kton 6,22 7,2 12.9 Average PEA Price THB/kWh 2.63 3.7 17. Average Gas Cost - Cogen business THB/mmBTU 257.5 31.8 2.7 Average Gas Cost - IPP business THB/mmBTU 249.2 33.2 21.7 (3) Coal Price FOB USD/Ton JPU 97.2 112.1 15.3 Freight Price USD/Ton actual 11.5 1.1-12. Availability - Cogen Business % 93.6% 95.5% Availability - GIPP % 96.3% 85.5% Availability - GHECO-One % 98.9% Unplanned Outage Factor - Cogen business % 1.9% 1.9% Unplanned Outage Factor - GIPP % 1.9%.9% Unplanned Outage Factor - GHECO-One % 1.1% IPP Heatrate BTU/kWhe 6,924 6,93.1 GHECO-One Heatrate BTU/kWhe 9,94 N/A Allocated Cogen Heatrate (Coal Units) BTU/kWhe 1,796 1,42-3.5 (4) Allocated Cogen Heatrate (Gas Units) BTU/kWhe 8,631 8,29-7. GSPP11&12 Heatrate BTU/kWhe 8,437 7,842-7. Exchange Rate THB/USD 3.77 31.18 1.3 Note: 1) Increase from new contracted capacity to EGAT 826 MW and ICs 4 MW and 41 tph. 2) Includes HHPC Electricity Sales of 9 GWh in 211 and 542 GWh in 212 3) Price excludes biomass which currently is used up to 5% of coal volume. 4) Includes GE Phase 5 Heat rate. 11
Revenue : Volumes EGAT EGAT IPP Business (GWh) 921 958 961 797 669 42 428 525 541 453 489 518 146 378 363 245 216 463 477 34 44 481 466 454 48 465 42 222 18 23 36 59 62 64 49 36 56 47 5 43 17 Jan-12 Feb-12 Mar-12 Apr-12 May-12 Jun-12 Jul-12 Aug-12 Sep-12 Oct-12 Nov-12 Dec-12 8, 6, 4, 2, EGAT IPP Business (GWh) 7,23 46.1% 4,93 1,826 4,841 4,835 9 542 211 212 (1) (2) IPP HHPC GHECO-One (3) 385 359 45 EGAT SPP Business (GWh) 448 443 424 42 412 424 399 377 469 (4) 6, 4, EGAT SPP Business (GWh) 5,11 + 23.8% 4,49 2, Jan-12 Feb-12 Mar-12 Apr-12 May-12 Jun-12 Jul-12 Aug-12 Sep-12 Oct-12 Nov-12 Dec-12 211 212 Note: 1) GIPP EGAT Sales lower vs. 211, due to scheduled major maintenance. 2) HHPC includes sales EDL 3) GHECO-One started recording on 19-Aug-212 4) SPP12 started COD on 12-Dec-212 12
Revenue : Volumes Industrial Customer Sales IC Power (GWh) IC Electricity Sales (GWh) 6, 4, 4,249 +9.2% 4,64 388 366 396 386 372 388 45 41 (3) 364 386 388 391 2, 211 212 Jan-12 Feb-12 Mar-12 Apr-12 May-12 Jun-12 Jul-12 Aug-12 Sep-12 Oct-12 Nov-12 Dec-12 IC Steam Sales (ktons) IC Steam Sales (ktons) 8, 6, 4, 6,22 +12.9% 7,2 656 617 638 649 562 564 571 582 (3) 55 516 576 584 2, 211 212 Jan-12 Feb-12 Mar-12 Apr-12 May-12 Jun-12 Jul-12 Aug-12 Sep-12 Oct-12 Nov-12 Dec-12 Note: 1) Industrial customer demand rebound to normal level despite effects from BSTE explosion in May-212. 2) Even though supply contracts to industrial customers have Minimum Take Obligation, fluctuation between MTO level and actual affects our performance. 3) The significant drop in Sep-12 was due to customer maintenance 13
Operating margin Average Gas Price Cogen (Bt/mmBTU) 35 311 3 257 +2.7% 25 2 4. 3. 2. Average IC Selling Price (Bt/kWh) 3.7 2.63 +17.% 15 211 212 1. 211 212 Average Gas Price IPP (Bt/mmBTU) 45 35 +21.5% 33 25 249 15 211 212 (1) Gas Price Change vs IC Tariff Change 3% Gas IC Gas IC 2.7% 2% 17.% 1.2% 1%.6% % FY-1 vs FY-11 FY-11 vs FY-12 Note : 1) IPP gas price is on pass-through basis. % Gas Price Change % IC Price Change 14
Jan-7 Mar-7 May-7 Jul-7 Sep-7 Nov-7 Jan-8 Mar-8 May-8 Jul-8 Sep-8 Nov-8 Jan-9 Mar-9 May-9 Jul-9 Sep-9 Nov-9 Jan-1 Mar-1 May-1 Jul-1 Sep-1 Nov-1 Jan-11 Mar-11 May-11 Jul-11 Sep-11 Nov-11 Jan-12 Mar-12 May-12 Jul-12 Sep-12 Nov-12 THB/kWh Gas and coal margin is going back to normal level 3.5 3. Avg. PEA Price Gas Cost Coal Cost.49 THB/kWh 2.5 2. 1.5 EGAT s fuel subsidization Average =.6 THB/kWh Average = 1.7 THB/kWh EGAT s fuel subsidization 2.4 THB/kWh 1..5 Operating margin for both gas and coal are eased after Ft adjustment: Gas price continued to increase, while global coal index declined Ft was adjusted by +.3 THB/kWh for Jun-Aug and +.18 THB/kWh for Sep-Dec. Our coal cost for 212 and 213 has been hedged, while coal index has decreased. Note: 1) PEA Price = Base Tariff assumed at 1.8 THB/kWh + actual FT until Jun 211 and at 2.8 THB/kWh + actual FT since Jul 211 2) Gas Cost = Blended SPP gas costs in THB/mmBTU x Constant Gas-fired heatrate of 8,8 * BTU/kWh / 1^6 (*8,6 BTU/kWh since Nov 211 from efficiency of Phase 5) 3) Coal Cost = Average FOB Coal Cost in THB/mmBTU x Constant Coal-fired heatrate of 1,3 BTU/kWh / 1^6 15
Gas margin tightened through May-12, then relieved by increasing of Ft 2.76 2.76 2.76 2.76 2.76 PEA Tariff (THB/kWh) 3.6 3.6 3.6 3.24 3.24 3.24 3.24 Jan-12 Feb-12 Mar-12 Apr-12 May-12 Jun-12 Jul-12 Aug-12 Sep-12 Oct-12 Nov-12 Dec-12 Electricity Margin (THB/kWh) Gas Margin Coal Margin 1.44 1.47 1.62 1.71 1.69 1.39 1.34 1.38 1.9 1.91 1.88 2.4.28.2.2.21.13.34.33.31.55.47.45.49 Jan-12 Feb-12 Mar-12 Apr-12 May-12 Jun-12 Jul-12 Aug-12 Sep-12 Oct-12 Nov-12 Dec-12 Gas Price (THB/mmBTU) 289.41 298.64 298.54 296.6 36.1 317.37 318.51 32.88 313.67 322.57 324.77 32.34 Jan-12 Feb-12 Mar-12 Apr-12 May-12 Jun-12 Jul-12 Aug-12 Sep-12 Oct-12 Nov-12 Dec-12 Note : 1) Ft increase 3 Satang in Jun-12 and 18 Satang in Sep-12 16
Coal & Freight Cogen Business 211 212 212 vs 211 % COAL CONSUMPTION @ 26.59 mmbtu/ton JPU TON JPU 998,19 983,538 (14,48) -1.5% AVERAGE JPU&ABARE COAL INDEX USD/TON JPU 121.9 119.2 (2.7) -2.2% AVERAGE COAL PRICE AT FOB USD/TON JPU 97.2 112.1 14.8 15.3% FREIGHT PRICE USD/TON actual 11.5 1.1 (1.4) -12.% TOTAL COAL PRICE (CIF) USD/TON JPU 112. 124.9 12.9 11.5% TOTAL COAL PRICE (CIF) THB/mmBTU 129.6 146.4 16.9 13.% For 212, locked open position at 114 USD/Ton JPU (FOB), compared to average FOB price of 97.2 USD/Ton JPU in 211. For 213, has locked open position at 85 USD/Ton JPU (FOB), compared to current Coal index (average of JPU&BREE index) at 112.23 USD/Ton JPU Note: Average JPU&BREE Coal Price Index - Apr 29 Mar 21 : 7.18 USD/Ton JPU. - Apr 21 Dec 21 : 98. USD/Ton JPU (Coal Price Index is adjusted and retroactive to April 21) - Jan 211 Mar 211 : 98.95 USD/Ton JPU. - Apr 211 Mar 212 : 129.59 USD/Ton JPU. - Apr 212 Mar 213 : 112.23 USD/Ton JPU. 17
Production (GWh) Water Level (m.a.s.l) HHPC has returned to normal operation in 212 7 6 Annual Production and Water Level 617.5 592.6 577.7 Energy Production Reservoir W.L end of June Reservoir W.L end of Year 542.2 885 88 5 466.3 474.7 875 4 429.2 41.3 428.8 392.6 37.4 87 3 254.1 865 2 192.4 86 1 89.5 855 1999 2 21 22 23 24 25 26 27 28 29 21 211 212 Year HHPC has good rainfall of 2,492 mm. in 212, compared to 2,295 in 211 With high amount of water in reservoir, we planned to maintain at least 469 GWh production in 213 85 18
Summary of Results EBITDA Consolidated EBITDA Analysis (+3,116mn / +31.3%) 15, 13, 11, 9, 7, 5, +1,845 +683 +7 13,7 9,954 +537 (19) COD in Q3-12 211 Cogen IPP GHECO-One HHPC Others 212 Cogen business EBITDA IPP business EBITDA 1, 8, 6, 4, 2, 6,916 +536 mn 7.8% 7,452 6, 4, 2, 3,19 +2,59 mn 8.7% 5,618 211 212 211 212 Note : 1) All Figures in THB Millions. 19
Key Drivers EBITDA 8, 6, 4, 2, 6,916 Cogen Business EBITDA Analysis (+537 mn / +7.8%) +1,265 (378) (351) Volume (+67) Capacity (+589) Margin (+43) Others (-37) Routine (-243) AB-Inspection (-19) LTSA (-26) Electricity and operations (-14) Admin Expenses (-82) Right of Use (-47) Others (-82) 7,452 211 GM Impact Cogen Maintenance Other Operation 212 6, 5, 4, 3, 2, 1, 3,19 IPP Business EBITDA Analysis (+2,59 mn / +8.7%) (19) Volume Planned Outage +683 +1,845 Started operating 211 GM Impact GIPP GM Impact HHPC EBITDA Impact GHECO-One 5,618 212 Note : 1) All Figures in THB Millions. 2
Key Drivers Normalized Net Profit Cogen Business NNP IPP Business NNP 4, 3, 2, 1, 3,17 2,912-16mn -3.5% 3, 2, 1, 1,92 +1,613 mn +147.6% 2,75 211 212 211 212 Consolidated NNP (+975 mn / +23.7%) 8, 6, 4, 2, 4,14 +3,116 (1,88) (829) +221 +117 Phase 5 GHECO-One Lower rate Phase 5 GHECO-One 211 EBITDA Impact Depreciation Income Tax Interest Expense Financial Expenses (562) 5,78 Minority Interest 212 Note : (1) All Figures in THB Million.. 21
Financial Status 22
Summary Cash Flow Statement Of the THB 11,861 mn (1) ending cash balance of 31 Dec 12 THB 3,94 mn is in Cogen Business THB 7,921 mn is in IPP Business (2) Debt Repayment in 212 GE THB 3, mn in Dec-12 GIPP USD 7.9 mn in Jun-12 USD 11.7 mn in Dec-12 HHPC THB 3.4 mn & USD 1.7 mn in Jun-12 THB 3.4 mn & USD 1.7 mn in Dec-12 GHECO-One THB 331.9 mn & USD 16.2 mn in Oct-12 Note: (1) Ending Balance 11,861 Bt mn excludes temporary investments of 1,134 Bt mn (Cogen 1,6 Btmn + IPP Business 128 Btmn) (2) IPP Business consists of IPP, GHECO-One, and Houay Ho Power. 23
212 213 214 215 216 217 218 219 22 221 222 223 224 225 226 227 228 212 213 214 215 216 217 218 219 22 221 Key Financial Indicators : Outstanding Debts 212 3, Cogen Repayment Profile (MTHB) 6, 6, 5,5 5,56 5,6 4, 3,4 5,555 MTHB 8, 7, 6, 5, 4, 3, 2, 1, Consolidated Group Gross Debts 73,666 73,358 41,224 42,584 32,441 3,773 211 212 Cogen Business IPP Business Total Gross consolidated Debt was 73,358 MTHB in 212 versus 73,666 MTHB in 211 IPP Business Repayment Profile (MUSD) GHECO-One* 58 7 67 61 58 65 28 6 5 7 7 7 7 7 2 25 22 23 17 18 13 38 8 34 3 37 36 HHPC* IPP 3 25 29 26 9 * HHPC and GHECO-One Loan consists of USD tranche and THB tranche (converted @ 3 Baht/USD) 24
Key Financial Indicators 211 212 DSCR IPP (incl. cash) 2.72 (5.98) 2.82 (6.53) DSCR Cogen (incl. cash) 1.94 (2.95) 3.62 (6.2) D/E Ratio Conso: Gross D/E (Net D/E) 2.15 (1.9) 1.99 (1.64) Cogen: Gross D/E (Net D/E) 1.2 (1.8) 1.16 (1.2) Interest Coverage Ratio Cogen 7.88 5.99 s long term target is to maintain the following DSCR excluding cash on hand of not less than 1.6x D/E of not more than 1.x but allowing for temporary hike if due to consolidation effect during construction ICR of not less than 5.x D/E ratio is expected to start decreasing from scheduled debt repayment. Note : IPP - DSCR = ( IPP EBITDA) / (Principal + Interest + Financial Charge) Cogen - DSCR = ( Cogen EBITDA + Dividend from IPP business) / (Principal + Interest + Financial Charge) Gross D/E = Total Outstanding Debts / Total Equities Net D/E Cogen - ICR = (Total Outstanding Debts cash) / Total Equities = ( Cogen EBITDA + Dividend from IPP business) / (Interest) 25
Expansion Program Completed 4, MWeq SPP11 & 13 (1) GHECO-One 3,5 3, 2,5 2, 1,5 1% 18% Houay Ho; Hydro IPP 152 MW Stake @ 67.25% HHPC 114% CFB3; 115 MWeq coal-fired cogen Q1-9 Q2-9 Q3-9 Q4-9 Q1-1 Q2-1 Q3-1 Q4-1 Q1-11 Q2-11 Q3-11 Q4-11 Q1-12 Q2-12 Q3-12 Q4-12 121% 14% Phase 5; 382 MWeq gas-fired cogen SPP11 & 13; 143 MW gas-fired cogen 174% 18% GHECO-One; 66 MW Coal-fired IPP Stake @65% Solar AIE 1.55 MW solar farm SPP12; 11 MW gasfired cogen Solar AIE Capacity as of Q1-29 : 1,996 MWeq Q4-212 : 3,53 MWeq (increase of around 8% ) CFB3 Phase 5 SPP12 (2) Note: (1) SPP11 & SPP 13 are formerly known as TNP1 and RNP respectively. (2) SPP12 is formerly known as TNP2. 26
Thank you 27
Q&A 28