E-235 VOL. 28 500 KV TRANSMISSION SYSTEM...

E-235 VOL. 28

500 KV TRANSMISSION SYSTEM PROJECT

FOR

INDEPENDENT POWER PRODUCERS

ELECTRICITY GENERATING AUTHORITY OF THAILAND

REPORT NO. 21200-3901 SYSTEM PLANNING DEPARTMENT

JANUARY 1996

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500 KV TRANSMISSION SYSTEM PROJECT

FOR

INDEPENDENT POWER PRODUCERS

REPOR'I NO. 21200-3901

JANU]ARY 1996

Prepared By: Concurred By:

Transmission System Planning Divisionviston____i_' __

(Prakob Dhienhirunya)

Assistant Director, System

Planning Department

Submitted By: Approved By:

~ (Prutichai Chonglertvanichkul) (Koomchoak Biyaem)

Chief, Transmission System Director, System Planning Department

Planning Division

ABBREVIATIONS

ACSR - Aluminum Conductor Steel ReinforcedADB - Asian Development BankBVI - Black & Veatch International CompanyB/C - Benefit/Cost Ratiocct-kn - Circuit-KilometerDC/ST - Double Circuit/Steel TowerDR - Discount RateEDR - Equalized Discount RateEGAT - Electricity Generating Authority of ThailandEHV - Extra High VoltageF.C. - Foreign CurrencyGIS - Gas Insulated SwitchgearHVAC - High Voltage Altemating CurrentHVDC - High Voltage Direct Current

IBRD - International Bank for Reconstruction and DevelopmentIDC - Interest During ConstructionIPP - Independent Power ProducerL.C. - Local CurrencyMTHB - Million BahtMEA - Metropolitan Electricity AuthorityMCM - Thousand Circular MilsMVA - Megavolt-ampareMVAr - Megavolt-ampere ReactiveMW - MegawattNEPC - National Energy Policy CouncilNEPO - National Energy Policy OfficeNESDB - National Economic and Social Development BoardNESDP - National Economic and Social Development PlanNPV - Net Present ValueOECF - The Overseas Economic Coorporation FundPDP - Power Development PlanPEA - Provincial Electricity AuthoritySPP - Small Power ProducerTDRI - Thailand Development Research InstituteTHIB - Thai BahtTLFS - Thailand Load Forecast SubcommitteeUSD - US DollarVAT - Value Added TaxW/O - Without

TABLE OF CONTENTS

Page

1. INTRODUCTION I

2. SUMMARY AND RECOMMENDATIONS 3

3. LOAD FORECAST AND POWER DEVELOPMENT PLAN 6

4. 500 KV TRANSMISSION SYSTEM PROJECT FOR 10

INDEPENDENT POWER PRODUCERS (IPPs)

4.1 500 kV Transmission System in the Western Area 114.2 500 kV Transmission System in the Eastern Area 12

4.3 Cost Estimate 1344 Avn ndi$iirp qrChede 14

4.5 Implementation Schedule 15

5. POWER SYSTEM STUDIES 31

6. ECONOMIC ANALYSIS 39

7. FINANCLAL JUSTIFICATION OF THE PROJECT 50

8. SHUNT REACTOR SIZING 61

REFERENCES 70

APPENDIXES

1. Substation Load Forecast 712. Power Flow Diagrams 813. Dynamic Stability Curves 1194. Fault Flow Diagrams 2055. Full Name and Abbreviation of Substation 211

V~~~~~~ ~ ~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~ - 1 0

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1. INTRODUCQ IN

The electric power consumption in Thailand has increased very rapidly. The

average growth rates of peak demand recorded in the last five years were at two digits, and

the continuously rapid increase is foreseen in the latest load forecast. A huge investment

program is required for EGAT, who is responsible for the provision of the sufficient and

reliable electricity generation, and also to build the necessary new power plants and

transmission system facilities to meet the growing demand.

EGAT so far has successfully managed in the financing programme, mainly on

the international capital market and from official sources, such as export credits, IBRD,

ADB and OECF. The rapidly increasing volume of capital investment and loans from the

international market for EGAT alone has exceeded the national foreign borrowing ceiling

imposed by the Government.

The Government also has the policy on the privatization of power supply industry

to increase the competitiveness in electricity business, as well as to increase the efficiency

and to reduoe the investment in the public sector. In September 1992, the cabinet approved

a directive, the Four-Step Plan, for the Thai Power Utilities to perform and restructure their

organizations in response to the privatization policy. The Four-Step Plan has included three

forms of private participation in the power sector: (i) Subsidiary companies, (ii) Small

Power Producers (SPPs), and (3) Independent Power Producers (IPPs).

In the third step of the Four-Step Plan, the activities involving EGAT for the

implementation in Fiscal Year 1995 includes the invitation announcement to the private

sector to participate in the build-own-operate (BOO) scheme of the power plants which are

scheduled for the commission during 1996-2002 as IPPs.

The current EGAT long term Power Development Plan (PDP 95-01) has included

a total power purchase from IPP up to the year 2011 of about 13,100 MW, representing

30 % of the total installed capacity. In the 7th NESDP, the power purchase from IPP

totalling 4,100 MW has been proposed, of which the first stage of 1,300 MW is scheduled

for commissioning during 1998-2000 and the second stage of 2,800 MW will be

commissioned during 2001-2002. The first solicitation to purchase electricity from IPPs of

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4,100 MW was announced on 15 December 1994, and there were more than 30 investor

groups submitting their 50 proposals on the bid openning day, 30 June 1995.

To facilitate the private sector investment in IPP projects, EGAT will construct

two 500 kV transmission lines along the Gulf of Thailand from Bang Saphan (PrachuapKhiri Khan Province) to Sai Noi and Wang Noi on the westem coast and from Rayong to

Nong Chok and Wang Noi on the eastern coast. These 500 kV lines will receive the power

from IPPs' power plants and transmit most of the generated power to the load centers which

are at Greater Bangkok and the surrounding areas.

This report presents the scope of work, tentative construction schedule, cost

estimate and expenditure schedule of the proposed 500 kV Transmission System Project for

Independent Power Producers. The results of the power system study to ensure the

satisfactory system operation are also included.

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2. SUMMARY AND RECOMMENDATIONS

2.1 Resulting from the Government's privatization policy, Four-Step Plan has been

issued under the Cabinet's resolution on 12 September 1992 to direct the Thai power utilitiesto restructure their organization to be as the business-like operation organizations, andeventually convert themselves, parts or whole, from the state power utilities into publiclimited companies. The Four-Step Plan has also included the promotion of private sectorparticipation in the investment of power generation in the form of Independent PowerProducers (IPPs).

2.2 According to EGAT's Power Development Plan (PDP 95-01), during the 7thNation Plan, EGAT has given a total capacity of 4,100 MW power plant projects to theprivate sector as the IPPs through the competitive bidding process. The first solicitation wasannounced on 15 December 1995 to purchase electricity from IPPs for the first stage of1,300 MW which will be completed within 1998-2000, and the second stage of 2,800 MWto be in operation in 2001 and 2002. Another capacity of 4,000 MW IPPs are expected tobe solicited during ihe oth National Plani.

2.3 The preferable sites of the large IPP projects will be in the areas of Westem andEastem Seaboard. To facilitate the connection of IPPs with the national network, the EHV

transmission trunk lines along the Gulf of Thailand are required.

2.4 The study on the long-tern transmission development in the western area hadbeen previously carried out by the engineering services of Black & Veatch International(BVI) in association with Power Technologies Inc. (PTI). The main objective of the study

was to determine the transmission system for interconnection of 10,000 MW thermal powerplants near Bang Saphan in Upper Southern Thailand with Greater Bangkok through year2008. The study report titled "Feasibility Study for Transmission System Development forSouthern Power Plant Project" was completed in March 1994. The study has examined thefeasibility of using three basic systems, they are 500 kV HVAC, 765 kV HVAC and +500kV HVDC, and the 500 kV HVAC is recommended.

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2.5 Based on the BVI/PTI studies, 500 kV transmission lines along the Gulf ofThailand from Bang Saphan to Sai Noi/Wang Noi on the west coast and the others fromRayong to Nong Chok/Wang Noi on the east coast are planned to accommodate the powerplant projects for the total capacitv of about 10,000 MW in each area.

2.6 Part of the new 500 kV transmission system in the western area will beimplemented for the Ratchaburi Power Plant Project which has been planned for a combinedcapacity of 4,600 MW (1,800 MW combined cycle and 2,800 MW oil/gas fired thermalpower plants) to utilize the natural gas from Myanmar. Therefore the additional 500 kVtransmission system to accommodate the planned IPP projects will consist of two double-circuit 500 kV lines from Bang Saphan to Chom Bung or Ratchaburi 3 Substation, whichwill be a new 500 kV substation to be constructed for Ratchaburi power plant, and themaximum transfer capability to accommodate the new IPP power plants will be about 5,800MW.

2.7 The development of the eastern 500 kV transmission lines consists of a doublecircuit 500 kV line from Rayong 4 to Nong Chok and a double circuit 500 kV line fromRayong 4 to Wang Noi. The lines can accommodate the maximum power transfer of about

*8,800 MW.

2.8 The total estimated cost for the 500 kV Transmission System Project for IPPsbased on 1995 price level is THB 30,470.0 million, comprising the foreign currencyrequirement of THB 9,735.0 million (USD equivalent 389.4 million )1f and local currencyportion of THB 20,735.0 million. The estimated cost of the project which consists of twoparts : (i) the western 500 kV transmission lines, and (ii) the eastern 500 kV transmissionlines, can be summarized as follows:

Foreign Currency Local Currency Total(MTHB) (MTHB) !MT£B)

The western 500 kV lines 6,455.0 12,755.0 19,210.0The eastern 500 kV lines .280.0 7Q980 11,260.0

Total 97470 0

Note : 1/ 1USD =25 THB

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2.9 The proposed in-service date of this 500 kV transmission system for IPP Projectis Setember 2000.

2.10 The 500 kV transmission systems for IPPs on the west and east coast are provedto be the least cost alternative to transmit bulk power from those IPPs to EGATs loadcenters. The net present value at 10 % real discount.rate when compared to the 765 kVtransmission system altematives are THB 1,719.3 million and THB 3,754.8 million for westand east coast respectively.

2.11 The economnic internal rate of return (EIRR) of the project was conducted bycomparing the project cost with its benefit which was calculated by using two approaches,they were the outage cost reduction and the revenue made available from the incrementalenergy sale. The EIRR of the two approaches are as follows:

- For Approach I 107.01%

- For Approach 2 = 22.63%

2.12 The financial internal rate of return (FIRR) calculated based on the revenue fromthe incremental energy sale is 22.23 %.

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3. LOAD FORECAST AND POWER DEVELOPMENT PLAN

3.1 Load Forecast

The peak, gneration of EGCAT svytem was recorded at 12,267.90 MW on May

26, 1995. The latest load forecast prepared by the Thailand Load Forecast Subcommittee

(TLFS)V issued in June 1994 (Revision of June 1993 Forecast) has indicated that the peak

generation requirement would increase to 13,009 MW by the end of 1996. The peak

generation would be 19,029 MW in 2001; 25,371 MW in 2006; and 33,532 MW in 2011.

This forecast represents an average annual growth rate of 10.09 % during the 7th NESDP

(1992-1996). The growth rates are expected to decline to 7.90 %, 5.92 % and 5.74 % in

the periods of 8th NESDP (1997-2001), 9th NESDP (2002-2006) and 10th NESDP (2007-

2011) respectively. The 1994 TLFS Load Forecast for the total EGAT generation

requirement is shown in Table 3.1.

3.2 Power DeveloDment Plan

The latest PDP (PDP 95-01) has been prepared under the rapid changing

situations due to the uncontrollable incidents and the Govemment Policy on the power

supply industry in Thailand. The uncontrollable incidents were such as: (i) the shortage of

water inflow in the existing dan reservoirs; (ii) the obstacles to implement several projects

previously proposed due to lack of the public acceptance on hydroelectric projects, and the

environmental problems on the new proposed coal/lignite-fired power plant sites at Ao Phai

and Lampang; and (iii) the changes in natural gas supply situations due to the

unconfirmed status on gas supply from Malaysia, while the imported gas from Myanmar

Note: I/ The Thailand Load Forecast Subcommittee is a subcommittee of the National

Energy Policy Formulation Committee. The group is made up of

representatives from NEPO, EGAT, PEA and MEA. Outside consultants from

TDRI, Monenco Consultants Ltd. of Canada, Bugach Associated Ltd. of

Canada, and Dr.Tienchai Chongpeerapien of BERA Ltd. Thailand, had assisted

the Subcommittee to prepared the 1993 Load Forecast.

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was under negotiationsi. The Government policy on the power suppiy industry in Thailarid

has been set forth to cover: (i) the purchase of electricity from Independent Power

Producers (IPPs) under the aggressive program on the private sector participation in power

generation, as well as the purchase of electricity from neighboring Lao PDR, and (ii) the

improvement of power supply reliability to cope with the growing economy of the country.

The new Power Development Plan (PDP 95-01) has been formulated based on

the following updated information: (i) reducing the dependable capacity of the five existing

hydro power plants by a total of 600 MW., (ii) indefinitely postponing Kaeng Krung and

Mae Lama Luang hydroelectric, Lampang lignite-fired and Ao Phai coal-fired power plant

projects; (iii) increasing the power generation reserve margin from the current 15 % to

25 % from the year 2001 onwards; and (iv) delaying the retirement dates of some existing

power plants.

The PDP 95-01 comprises power generation and transmission projects which

have been approved and committed for construction; and it is also supplemented with

several projects including the purchased power from IPPs which is planned to provide

sufficient, and reliable power supply at reasonable prices.

Table 3.2 shows the list of projects in PDP 95-01 (Recommended Plan).

Note 1/ Negotiation on the purchasing of natural gas from Myanmar's Yadana field

has been concluded on 9 September 1994.

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Table 3.1 Total EGAT Generation Requirement(1994 TLFS Forecast)

Peak Generation Energy Generation Load

Fiscal Increase increase FactoYear MW GWh %

___________ MW _____ GWh %

Actual1984 3,547.30 343.00 10.70 21.066.44 2,000.14 10.49 67.791985 3,878.40 331.10 9.33 23,356.57 2,290.13 10.87 68.751 986 4,180.90 302.50 7.80 24,779.53 1,422.96 6.09 67.661987 4,733.90 553.00 13.23 28,193.16 3,413.63 13.78 67.991988 5,444.00 710.10 15.00 31.996.94 3,803.78 13.49 67.091989 6,232.70 788.70 14.49 36.457.09 4,460.16 13.94 66.771990 7,093.70 861.00 13.81 43.188.79 6,731.69 18.46 69.501991 8,045.00 951.30 13.41 49,225.03 6,036.25 13.98 69.851992 8,876.9(J 831.90 10. 34 5o,006.44 6, 7°1 .41 13.78 72.021993 9,730.00 853.10 9.61 62,17',;73 6.173.29 11.02 72.951994 10,708.80 978.80 10.06 69,651.14 7,471.41 12.02 74.25

Average Growth1985-1994 - 716.15 11.68 4,858.47 12.70 -

Forecast1995 11,880.00 1,171.20 10.94 78,023.00 8,37i.86 12.02 74.971996 13,009.00 1, 129.00 9.50 85,571.00 7,548.00 9.67 75.091997 14,193.00 1,184.00 9.10 92,879.00 7,308.00 8.54 74.701998 15,315.00 1,122.00 7.91 100,383.00 7,504.00 8.08 74.821999 16,446.00 1,131.00 7.38 108,160.00 7,777.00 7.75 75.082000 17,685.00 1,239.00 7.53 116,795.00 8,635.00 7.98 75.392001 19,029.00 1,344.00 7.60 126,025.00 9,230.00 7.90 75.602002 20,237.00 1,208.00 6.35 134,041.00 8,016.00 6.36 75.612003 21,440.00 1,203.00 5.94 142,849.00 8,808.00 6.57 76.062004 22,690.00 1,250.00 5.83 152,529.00 9,680.00 6.78 76.742005 23,997.00 1,307.00 5.76 162,187.00 9,658.00 6.33 77.152006 1 25,371.00 1,374.00 5.73 1 171,745.00 9,558.00 5.89 77.282007 26,835.00 1,464.00 5.77 181,745.00 10,000.00 5.82 77.312008 28,409.00 1,574.00 5.87 193,505.00 11,760.00 6.47 77.762009 30,044.00 1,635.00 5.76 204,956.00 11,451.00 5.92 77.882010 31,749.00 1,705.00 5.68 216,428.00 11,472.00 5.60 77.822011 1 33,532.00 1,783.00 5.62 228,445.00 12,017.00 5.55 77.77

Average Growth |

1982-1986 - 318.44 10.06 - 1,763.91 9.20 -

1987-1991 - 772.82 13.99 - 4,889.10 14.711992-1996 - 992.80 10.09 - 7,269.19 11.69 -

1997-2001 - 1,204.00 7.90 - 8,090.80 8.05 -

2002-2006 - 1,268.40 5.92 j - 9,144.00 6.39 -

2007-2011 - 1,632.20 , 5.741 - j 11,340.00 5.871 -

-8--

Table 3.2List of Projects in the Recommended PDP(1995-2011)

Power Plant Fuel Lid Rting TOtWl Colum _nllTM-e rNober fSn amW pot

Yhafom CC I (Sa) - 1 226 226 Febuary 19958SHldt Hydro 4 125 125 March 1995Mae Mob IgpiuM 12 300 300 May 1995Nons ChokGm Turbine DIesd 1-4 122 413 May95 - Aug 1995SolNolGm Turlbie DBei 1-2 122 244 May95 - Jun 1995Me Meob Linle 13 300 300 November ImRhbu o P ped-tue Hyro 8 168 163 December 1995WIg Nd CCI (GT) Gm 1-2 223 446 Mar96 - May 1996Wang Nd CC2 (GI) Go 1-2 223 446 Jul g6 - Aug 1996South BagOkCC2 (GI) Gm 1-2 202 404 Oct 96 - Nov 1996EGAT-TNB Stage U Intereomectku - 300 300 Apra 1997Wa No CCI (8T) - 1 205 205 AprO 1997Wan Nd CC2 (S) - 1 205 205 Jul 1997SOuth Bang_kCC2(ST) - 1 219 219 August 1997Lanm Taoug Puped-Storag Hydro 1-2 250 50o Febraq 2000

Wag NoICCStoge2(GI) Ga 1-2 200 400 Nov 97 - Dec 1997Purchased Power - 300 300 Januay 199SRatehabai CCI (Gl) Gm 1-2 200 400 Jul93 - Aug 19fRatchhubi CC2 (CG) Gm 1-2 200 400 Sep 98 - Oc 199Wuag NeiCCSbtge2(ST) - 1 200 200 November 1993Ratdaburl CC3 (G) Gm 1-2 200 400 Nov 98 - Dec 199fPurchJed Power - - 300 300 Janua 1999Ratckabud Therall Ol/Ca 1 700 700 Apr1 19fRakdabul CCl (51) 1 200 200 July 19g9RatchaburThermal OIWm 2 700 700 Aug" 1999

asaui cm (SI) 1 200 200 Septmber 1999Puarcased Power - 300 300 Ociober 2q99Rathburd CO (ST) - I 200 200 November 1999Purhad Power - 400 400 Jaur 2000Krbl/SuraTh"iTberd Oil/Gs 1 300 300 J-nuy 2000Rathahr TherFa OilGs 3 700 700 October 2000Ratcdabud Thead OWGl/ 4 700 700 Februay 2001Purduaed Poer - 1400 1400 AprO 2001Southem Reoo Therma OiGa 1 300 300 March 2002Purchaed Power - 1400 1400 Aprl 2002Purched Power - 1000 1000 J qur 2003Lh- Tahug Pumped-Ste Hydro 3-4 250 500 Apri 2003P-raedt Power - 1000 1000 Jana 2004Southern Reglon Thermal OlGas. 2 300 300 January 2004Chulabhon Pumped-Stope Hydro 1-2 200 400 April 2004Purchased Power - 1000 1000 Jaury 2005NewTmbnua Co- 1 1000 1000 Apr41 2005Purchsed Power - 1000 1000 Januy 2006New Thernml Coal 2 1000 1000 Apri 2006Purchased Power - 1000 1000 Janua 2007Southen Regio Therml OilG 3 300 300 Jaury 2007New Theral C-ol 3 1000 1000 Aprg 2007Purchased Power - 1000 1000 Janua 2008Chuabborn Puped-Storae Hydro 3-4 200 400 JaUa1ry 2008Khlldhn Pmped-Storage Hydro 1-2 200 400 March 2006New Thermal C-I 4 1000 im Apri 2008Purhaed Power - 1000 1000 Jaur 2009Southe Reago ThalD OlGa 4 300 300 Jauay 2009New Thermrl C-I 5 1000 1000 Apri 2009PUrsed Power - 1000 1000 Janury 2010New Thead OilGs I 1000 1000 Apr4 2010New Pearg GT DWel 1-3 100 300 Apd 2010Purchased PFer - 1000 1000 Jary 2011Sou8her RePmgi Termal OIGU 5 300 300 JanUa 2011New Then_I OLGas 2 1000 1000 April 2011

Easin Caft by Septm r 1994 - 12911.9 MWTObl Added Capd (Up to 2011) 33,6760 MW

l R ioAn-u- 2.747.1 MWTOW Capait by Yer 2011 - U|23MW

-9-

4. 500 KV TRANSMISSION SYSTEM PROJECT FOR INDEPENDENT

POWER PRODUCERS (IPPs)

In June 1993, EGAT entered into a contract with Black & Veatch International

Company (BVI) who was engaged in association with Power Technologies, Inc. (PTI), to

undertake the feasibility study for Transmission System Development for Southern Power

Plant Projects where all power plants were assumed to be located near Bang Saphan in

Prachaup Khiri Khan province. The purpose of the study is to determine the most

appropriate transmission system requirement to transmit 10,000 MW of power from new

power plants to the Greater Bangkok Area. The study which was completed in March 1994,

recommended that 500 kV system is the preferred transmission system based on the

technical and economical justification. The proposed 500 kV system would be consisting

of thrree double-circuit lines from Bang Saphan to an intermediate substation assumed to

be located at Chom Bung district in Ratchaburi province. From this intermediate substation,

the 500 kV lines are further extended to link with the 500 kV system in Greater Bangkok

Area with one double circuit line termninating at Sai Noi Substation, and another double

circuit line terminating at Wang Noi Substation. The study also recommended that in case

of the difficulty to obtain the right-of-way for the third 500 kV double circuit line from

Bang Saphan to the intermediate substation, the installation of series compensators on the

first two 500 kV double circuit lines between Bang Saphan and intermediate substation was

considered as an alternative.

The transmission plan recommended in the BVI/PTI Study Report is actually the

main power transmission trunk line to facilitate the connection of the IPP projects in

western areato the EGAT system. Based on PDP 95-01, the 500 kV transmission plan for

the power plant projects in the western area has been reviewed and the transmission system

studies have been extended to cover the transmission systemn requirement for the power plant

projects to be developed in the eastern area using the same approach and methodology of

BVI/PTI study.

Based on the results of the reviewed study, the 500 kV Transmission System

Project for Independent Power Frouuceis -which have been divided in.to wo parts, arg a

follows;

-10-

4.1 500 kV Transmission System in the Western Area

(a) Construction of two routes of the 500 kV double circuit line from Bang

Saphan to Chom Bung (a new 500 kV substation to be constructed for Ratchaburi Power

Plant Project), using 4xl272 MCM ACSR conductors per phase. The distance of the two

line routes are approximately 275 km and 280 km respectively. One overhead ground wire

with optical fibre would be provided.

(b) Construction of a 50C) kV Bang Saphan Substation to accommodate four 500kV outgoing lines to Chom Bung and one 500/230 kV interbus transformer rated

600/800/1000 MVA (consisting of four single-phase units, inclusive of one spare unit, each

rated 200/267/333 MVA). The existing 230 kV substation will be expanded to provide

space for the interbus transformer bank.

(c) Expansion of the 500 kV Chom Bung Substation to accommodate fourincoming lines trom Bang Saphan Substation

(d) Since the capacity of the 500 kV equipments of GIS substation at Sai Noi

can cazry the current up to about 3,000 ampere which is not sufficient to carry the additional

power from the West Coast IPP, so that it is necessary to construct a new 500 kV GIS

switchyard located next to the existing 500 kV GIS switchyard at Sai Noi Substation. The

double circuit 500 kV Chom Bung - Sai Noi line and one circuit of the 500 kV double-

circuit Chom Bung - Wang Noi line (to be constructed for Ratchaburi Power Plant Project)

will be sectionalized and they will be connected together at the new 500 kV GIS switchyard

at Sai Noi. The new switchyard will also provide four line bays for the future lines to

Bangkok Noi and Chaeng Watthana Substations.

(e) Installation of line shunt reactors rated 150 MVAr at both ends of the 500kV Bang Saphan - Chom Bung lines.

(f) Land procurement for the 500 kV Bang Saphan Substation.

(g) Addition of communication system.

-11 -

4.2 500 kV Transmission System in the Eastern Area

(a) Construction of two routes of 500 kV double circuit transmission line,

using 4x1272 MCM ACSR per phase, approximately 155 and 170 km for the the first and

second line routes respectively, from the proposed new 500 kV Rayong 4 Substation to

interconnect with the 500 kV Sai Noi (Wang Noi) - Nong Chok transmission line (T

Junction). At T Junction, one of the two lines of the 500 kV double circuit Wang Noi -

Nong Chok transmission line will be sectionalized and reconnected such that one 500 kV

double-circuit linr 4rrni; Rayong 4 Substation will be terminated at Wang Noi Substation and

the other line will be terminated at Nong Chok Substation. One overhead ground wire with

optical fibre will be eg .pped.

(b) Construction of a 230 kV double circuit Rayong 4 - Rayong 2 line, double

circuit on steel tower, using 4x1272 MCM ACSR conductors per phase, for a distance of

approximately 10 km.

(c) Construction of a 500/230 kV Rayong 4 Substation. The 500 kV switchyard

will be provided for the four 500 kV outgoing lines to Wang Noi and Nong Chok

Substations, and two 500/230 kV interbus transformers, each rated 600/800/1,000 MVA

(consisting of seven single-phase units inclusive of one spare unit, each rated 200/267/333

MVA). The 230 kV switchyard will be provided for the interbus transformers, and two 230

kV outgoing lines to Rayong 2 Substation.

(d) Expansion of the 230 kV Rayong 2 Substation for two incoming lines fromthe Rayong 4 Substation.

(e) Installation of line shunt reactors rated 80 and 100 MVAr at both ends ofthe 500 kV Rayong 4 - Nong Chok and the Rayong 4 - Wang Noi lines respectively.

(f) Land procurement for the 500 kV Rayong 4 Substation.

(g) Addition of communication system.

-12-

Figure 4.1-4.2 show the locations and preliminary line routes of the proposed 500kV transmission systems in the Western and Eastern Areas respectively Figures 4.3-4.4illustrate the single-line diagramn of the proposed 500 kV transmission systems in theWestern and Eastem Areas respectively.

4.3 Cost Estimate

The cost estimate of the 500 kV Transmission System Project for IPPs is basedon the EGAT standard design, including engineering and supervision, physicalcontingencies, escalation, import duties, interest during construction and value added tax(VAT) at the 1995 price.

The escalation factors for the foreign currency portion and local currency portionare as follows:

Escalation Factor (% Change)"Fiscal Year F.C. Portion 2 ' L.C. Portion 3/

1996 1.79 4.001997 2.59 40Q

1998 2.52 4.001999 2.46 4.002000 2.48 4.00

The cost estimate of the 500 kV Transmission System Project for IPPs is shownin Table 4.1. The estimated cost of the project which consists of two parts: (i) 500 kVsystem in the Western Area, and (ii) 500 kV system in the Eastern Area, are summarizedbelow:

Notes: 1/ Per annum growth rate from previous year.2/ G-5 MUV index from the World Bank Quarterly Report on Commodity

Markets and the Developing Countries, January 1995.3/ Local Consumer Price Index estimated by NESDB and Bank of Thailand,

1994.

-13-

Description Foreign Currency Local Currency Total(MTHB) (USD.Million)" (MTHB) (MTHB)

(i) 500 kV system in the Western area 6,4JJ0 (2582) 12,755. ,210 0(ii) 500 kV system in the Eastem area 3.280 0 (131.2) 7.980 0 11.260.0

Total 9.75. (38,4 2Q1 0 3.Q

4.4 Expenditure Schedule

The expenditure schedule of the 500 kV Transmission System Project for IPP isshown in Table 4.2. The annual disbursements are summarized as follows:

EXPENDITURE SCHEDULE OF 500 KV TRANSMISSION SYSTEM PROJECTFOR INDEPENDENT POWER PRODUCERS

IN WESTERN AREA

Fiscal Year Foreign Currency Local Currency Total(MT__B) (USD.MiIlionV' 0MDII) (MTHB)

1996 - - 157.7 157.71997 - - 288.3 288.31998 106.0 (4.3) 3,008.8 3,114.81999 3,928.6 (157.1) 4,817.2 8,745.82000 1,977.8 (79.1) 3,863.5 5,841.32001 442.6 (17.7) 619.5 1.062.1

Total 6, 455.0 1 2.58.2 1221Q

Note : 1/ Rate of exchange 1 USD = 25.0 THB.

-14-

EXPENDITURE SCHEDULE OF 500 KV TRANSMISSION SYSTEM PROJECTFOR INDEPENDENT POWER PRODUCERS

IN EASTERN AREA

Fiscal Year Foreign Currency Local Currency Total(MTHB) (IJSD.Million" (MTBB) (MTHB)

1996 - - 253.0 253.01997 - - 175.2 175.2

1998 62.5 (2.5) 1,795.1 1,857.61999 2,077.5 (83.1) 2,974.1 5,051.62000 934.4 (37.4) 2,390.7 3,325.12001 205.6 (8.2) 391.9 597.5

Total 3,280.0 71.l260.0

4.5 implementation Schedule

The proposed implementation schedule of the transmission system expansion forthe Western and Eastern Areas are shown in Tables 4.3 and 4.4. The expectedcommissioning date is ae2tember 2000.

Note I/ Rate of exchange 1 USD 25.0 THB.

-15-

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Table 4.1 Cost Estimate of 500 kV Transmission SystemProject for IPPs

F.C. L.C. Total(MTHB) (MTHB) (MTRIB)

IN WESTERN AREA

TRANSMISSION LINE

1. 500 kV Bang Saphan - Chom Bung I st Line Route(4xI272 MCM ACSR, DC/ST, 275 km, IncludingOptical Fibre with Overhead Ground Wire) 1,361.1 3,250.5 4,611.6

2. 500 kV Bang Saphan - Chom Bung 2nd Line Route(4x1272 MCM ACSR, DC/ST, 280 km) 1,293.4 3,294.0 4,587.4

Subtotal 2,654.5 6,544.5 9,199.0

SUBSTATION

3. 500/230 kV Bang Saphan Substation Expansion 632.0 298.1 930.14. 500 kV Chom Bung Substation Expansion 289.5 87.3 376.85. 500 kV Sai Noi Substation Expansion 1,592.0 106.1 1,698.16. Installation of Line Shunt Reactor at 500 kV

Bang Saphan - Chom Bung Lines 352.8 21.2 374.07. Communication System Addition 27.7 3.3 31.0

Subtotal 2,894.0 516.0 3,410.0Total Direct Cost / 5,548.5 7,060.5 12,609.0

INDIRECT COST

8. Engineering & Supervision - 630.5 630.59. Physical Contingencies 555.0 769.0 1,324.0

Total Cost (w/o Escalation, ImportDuties, IDC & VAT) 6,103.5 8,460.0 14,563.5

10. Escalation 351.5 1,236.5 1,588.0Total Cost (w/o Import Duties,

IDC-& VAT) 6,455.0 9,696.5 16,151.511. Import Duties - 742.5 742.5

Total Cost (w/o IDC VAT) 6,455.0 10,439.0 16,894.012. Interest During Construction - 1,454.0 1,454.0

Total Cost (w/o VAT) 6,455.0 11,893.0 18,348.013. Value Added Tax - 862.0 862.0

Total Cost 6,455.0 12,755.0 19,210.0

Note : / Price Level 1995.-25-

Table 4.1 Cost Estimate of 500 kV Transmission SystemProject for IPPs (Continued)

F.C. L.C. Total

(MTHB) (MTHB) vMT IT)IN EASTERN AREA

TRANSMISSION LINE1. 500 kV Rayong 4 - T Junction I st Line Route

(4x1272 MCM ACSR, DC/ST, 155 km, IncludingOptical Fibre with Overhead Ground Wire) 773.2 1,903.3 2,676.5

2. 500 kV Rayong 4 - T Junction 2nd Line Route(4x1272 MCM ACSR, DC/ST, 170 km) 785.3 2,069 7 2,855.0

3. 230 kV Rayong 4 - Rayong 2(4x 1272 MCM ACSR, DC/ST, 10 km, IncludingOptical Fibre with Overhead Ground Wire) 43.5 106.0 149.5

Subtotal 1,602.0 4,079.0 5,681.0SUBSTATION

4. 500/230 kV Rayong 4 Substation 872.6 449.8 1,322.45. 230 kV Rayong 2 Substation Expansion 40.7 9.6 50.36. Installation of Line Shunt Reactor at 500 kV

Rayong 4 - Nong Chok and Rayong 4 -Wang Noi Lines 286.6 23.5 310.1

7. Communication System Addition 18.6 2.6 21.2Subtotal 1,218.5 485.5 1,704.0Total Direct Cost a/ 2,820.5 4,564.5 7,385.0

INDIRECT COST8. Engineering & Supervision - 369.5 369.59. Physical Contingencies 282.0 493.5 775.5

Total Cost (w/o Escalation, ImportDuties, IDC & VAT) 3,102.5 5,427.5 8,530.0

10. Escalation 177.5 779.5 957.0Total Cost (w/o Import Duties,

IDC & VAT) 3,280.0 6,207.0 9,487.011. Import Duties - 416.0 416.0

Total Cost (w/o IDC VAT) 3,280.0 6,623 0 9,903.012. Interest During Construction - 866.0 866.0

Total Cost (w/o VAT) 3,280.0 7,489.0 10,769.013. Value Added Tax - 491.0 491.0

Total Cost 3,280.0 7,980.0 11,260.0TOTAL PROJECT COST 97-35. 20,735.0 30,470.0

(USD Million Equivalent / 389.4 829.4 1,218.8 )

Notes a/ Price Level 1995.k/ 1 USD = THB 25.0. -26-

Table 4.2 Expenditure Schedule of 500 kV T'ransmfission System Project for IPPs

(Million Baht)item ~~~~~Descoption TOtW 1996 1997 1998 1999 2000 2001

F.C L.C. Tota F.C. L.C. Tota F.C. L.C Tota F.C. L.C. Tota F.C L.C, Tota F.C L.C Total FC. LC. Tota

TRANSMISSION LINE

1 500 kV Buig Saphan - Cut Bung I st Lime Route(4xl272 MCM ACSR, DCIT. 275 kin,

nluhxogOptca1Fibmewih Ovuhead Oroqu

wire) 1,361.1 3,250.5 4,611.6 - 55 5.5 - 03.9 103.9 49.7 1.137.7 1,187.4 1.2219 1,095.0 2,316.9 39.8 725.1 764 9 497 1833 233 02 500 kV Bang Saplia - Cham Bwzg 2nd Line Route

(4x] 272 McMACSP,1:DC/ST, 2SOkrn) 1,293.4 3,294.0 4,527.4 - 5.6 5.6 - 105.8 10589 414A 1,156.6 1.198.0 1.17-75 1,107.2 2,284.7 33.1 73371 7668 414 1851 226.5

Subtota 2,654.5 6,544.5 9.199.0 - 11.1 11.1 209.7 209.7 91.11 2,294.3 2,385.4 2,399.4 2,202.21 4,601.61 72.9 1,45889 1,531 7 91 1 368 4 459,5

3 500'230kV BazaSpShm Suzdion Expuanion 632.0 298. 1 930-1 - 0100 000 - - 25.2 25 2 2149 717 2866 354.0 83.9 437 9 63 1 17 3 80 44 SOD0kV Chai Bunig Sdustation Expautilo 289.5 87.3 3768 - - . 98.4 36.2 134,6 162 2 42.4 204.6 2839 87 37 65 50okVSai Noi SubhalalzExpension 1,592.0 106.1 1,698.1 - - . - . - 5413 440 5853 891.5 51.5 943 0 159.2 10.6 16989

NJ 6 inswalatmnofLne Slzzt Raadgwat SODkV

Bospa-hmugie 352.81 21.21 374.0 - .- - - 120,0 8.8 2a 197.51 10.3 20789 35 3 2 1 37 47 ComnuaiicatmoSytaAddition 277 33 310 - . - - -- 2.8 0.31 3.1 22.1 2.7 24. 28 0 3 1

Subtot.a 2,394.0 536.0 3.410.0 IW10. 10D00 252 25,2 9774 161. DJ1,138.4 1,627.3 190.8 1,818.1 289.3 39.0 328 3TOtaDiz'eoCoet 8/5,548.5 7,060.51 12,609.0 111H 111.1 209.7 209.7 91.1 239.5 2,410.6 3,376.8 2,363.21 5,740.0 1,700.2 1,649.6 3.54989 380.4 4074 7878

8 Eazginveaizw&.Szqzaiaic - 630.5 630.5 -- - - 0 1.0 21.4 21.4 - 332.5 332.5 - 275,6 275 6. 9 PhyalCo,airmies 3555.0 769.0 1,324.0 - 11.1 1 - 21.1 21.1 9.1 234.2 243 3 337.9 269.4 607.3 170.0 192.5 362 5 38 0 40 7 78 710 Eacagic 351.5 1,236.5 1,588.0 - 2.4 214 - 14.0 14.0 5.8 265.9 271.7 213.9 437.1 651.0 107.6 409.2 516.81 24 2 1079i 132 111i n;wt Duties - 742.5 742.5 - - . .I. -- 501.9 501.9 - 240.6 240.6 - -

subtotal ~~~~~906.5 3,378.5 4,285.0 13.5 135 36.1 36.1 14.9 521.5 536.4 5518 1,540.91 2,092.7 277.6. 1,117.91 1,395.5 62.2 148 6 21081

To(alCost (W/o IDC &VAT) 6,455.0 10,439.0 16,894.0 - 124.6 1246 - 245.8 245.8 106.0 2,841.0 2,947.0 3,928 6 3,904.11 7,832.7 1,977.8 2,767.51 4,745 3 442 6 556.0 998 61 2 Interest DurnagConsbuctoni 1,454.0 1.454.0 - 33.1 33.1 42.5 42.5 - 124.6 1246 - 1 438.21 438.2 - 815~6 815.6 . - -

Total Cost (w/oVAT) 6.455.0 11,893.0 18,348.0 - 157.7 157.7 - 288:1 288.3 106.0 2,965.6 3.071.6 3.928.6 4,342.3 8,270 9 1,977 8 3,8. 5,560 9 4426 556 0 998,6

1 3 Value Added Tax 8 6201 86210 - .-- 42 4321 - I4.9 4749 84 280 4 - 63 5 63 5

TOWalCoat 6.45501 12,755.0 19.210.0 157.7 157 - 288.1 28831 106.0 3,00881 3,11481 3.928.6 4,1. ,48 1.977 8 3,83 5.1 44261 619 5 1.0621

~ 1PlioLcv 1995

Table 4.2 Expenditure Schedule of 500 kV Transmission System Project for IPPs (Continued)

(Million Baht)

it_n Desaption Totl 199 1997 199_ 1999 200D 2001

F.C. L.C. Total FPC. L C. Total F.C. L.C. Total F.C. L.C. Totl F.C. L.C. Total F.C. L.C. Total F.C. L.C. Total

TRANSMISSIONLINE

I SW kV Reg 4 -T Jcion st Line Route(4cI272 MCM ACSR. DMMST. 155 m 1cbxl*ngOicalFibe with Osead CrmdWir) 773.2 1,903.3 2,676.5 3.1 3.1 53.6 58.6 23S6 649.9 673S5 693.1 651.S 1,344.9 22.9 42'7.4 452.3 23.6 110 5 1391

2 500 kV Raym 4 -T btion 2nd Line Route

(441272MCMACSR, DYST. 1710km) 735.3 2,069.7 2,S55,0 3.4 3.4 64.2 64.2 25.1 710.7 735.8 715.0 706.2 1,421.2 20.1 46.5.t 485 9 25.1 119.4 144 5

3 230 kV Rr 4 -Rayctg 2

(4xl272 MCM ACSR, DCIST, 10 km, Incudi07Opt,cal Fibre wil Ovedtad Gunod Wire) 43.5 106.0 149.5 _ 0.2 02 32 7 565 392 9 6 41 54.7 1.2 4 2 5.4

SublaI 1,602.0 4,079.0 5.681.0 0.0 6.5 6.5 0.0 222.3 122.8 53.7 1,360.S 1,414.5 1,440.S 1.414.5 2,355.3 52.6 943 992.9 549 234 1 289 0

4 50/V230kVR R4Subtiotn 372.6 44938 1,322.4 200.0 2000 13.9 1S 9 296.7 95.7 392.4 438.6 1121 600.7 37 3 23.1 1104

5 230 kV Ry 2 Subswicn Expmiu 40.7 9.6 50.3 1 . 23.9 2.5 16.4 22. 6.1 28 9 4.0 1 0 5 0

00 6 1zbalai efLine Shmt Reaceat 500 kV

Rayo. 4 -Nmtg Cok wd Raog 4 -Wu NoiLinn 236.6 23.5 310.1 . . . . . . . . 23.7 2.4 311 229.2 237 2479 23.7 24 31 1

7 ComnmicationSysternidditio 23.6 26 21.2 . -. _ .9 03 2.2 143 2.0 163 2 9 0 3 2.2

Suial 1,213.5 435.5 1.704.0 200.0 200.0 1 .9 231.9 341.2 100.9 442.1 755.4 13 8 9 894 3 121.9 26 1243.7

Totl Dire Cost I| 2S,20.5 4,564.5 7,335.0 206.5 206.5 0.0 22.3 122.3 53.7 1,379.7 1,433.4 1,732.0 1.515.4 3,297.4 303.0 1,079.2 1,387.2 176 3 260.9 437 7

INDECT C>T____ _ _.._

S Eagjne ng&Supavision - 369.5 369.5 - - 12.0 2.0 .I 2. 2. 192.3 192. - 263 9 163.9

9 physica 2Cownrcies 232.0 493.5 775.5 20.7 20.7 12.4 12.4 5.4 139.3 144.7 181.3 171.0 352.3 77.6 124 0 201.6 17.7 26 1 43 3

10 Escaltion 177.5 779.5 957.0 4.5 4.5 S 2 32 34 1573S 161.2 114.2 276.7 390.9 48.S 263.2 312.0 III 69.1 S0 2I I lcat Duties - 416.0 416.0 .- -_ . 285.4 235.4 - 13106 130.6

Subtotal 459.5 2.053.5 2,523.0 _ 25.2 25.2 21.6 21.6 3.3 303.9 317.7 295.5 925.9 1,221.4 126.4 6121.7 308.1 23.3 95 2 124 0

Tots Cost(w/o EDC & VAT) 3,230.0 6,623.0 9,903.0 231.7 2317 144.4 144.4 62.5 1,688.6 1,751. 2,077.5 2,441.3 4,513.3 934.4 1,74509 2,695.3 205 6 3561 561 722 jatreDtDwuri Cuuuuctin - K6.0 t66.0 21.3 21 3 30.3 30.8 - 79.5 79.5 - 260.3 260. - 473 6 473.6 .

Total Cost(w/o AT') 3,230.0 7,439.0 10,769.0 253.0 253.0 1752 1752 62.5 1,763.1 1,330.6 2,077. 2,702.1 4,779.6 934.4 2,2t45 3,16S 9 205 6 356 1 561 7

13 Value Added Tax 491.0 491.0 27.0 27.0 o 272.0 2720 156.2 256.2 . 35 S 35 8

Total Cost 3.2t0.0 7,930.0 11,260.0 = 253.0 253.0 1 175.2 175.2 62.5 1,795.1 1,357.6 2,077.5 2,974 1 5,052.6 934.4 2,390 7 3,325 1 205.6 391 9 597 5TOTAL PROJECT COST 9,735.0 20,735.0 30,470.0 410-7 410.7 463.5 463.5 163.5 4,303.9 4,9724 6,06.1 7.7923 23,797.4 2,912 2 6,254 2 9,1664 64.82 p011 4 11.659 6

USD MillionEuent b 339.4 329.4 1,213.3 16.4 26.4 - .5 15.s 6.3 292. 1 939 240.2 311.7 551 9 116 5 250.2 3667 25 9 40 5 66 4

Notes :/ Priceevel v995.

b/ I0 USD = TIM 25.0.

Table 4.3 Implementation Schedule of 500 kV Transmission SystemProject for IPPs (Western ArVea)

1995 1996 19'3 1998 1999 2000 2001

F easibility Study I2 i ii X t1t[ f1 124 4 t1}8

Approval by EGAT Board._.. ........ .

Project Appraised by NESDS Hil I Ill I Il I 11 I .11II . I

Land Procurement &c Rights-of-Way I I H .l t 1 1 1 111 . .1 lll 1ll il 1ll 4 I

Line Routs Survey .llIl1illILLi llSI 111M 11111 IIIII

Se e U f@cations & Tender Document i i t4l | *_ _ LLt

B5id Ealaimon & Negotiaton lll||1 lllllW 0 1II I M t,I fi1 [ tt4

Substation_ .. - _. . 33 4 2 3t i E

TRIANS)aSSION SYSIS PLANNING DIVI'ION

Table 4.4 Implementation Schedule of 500 kY Transmission SystemProject for IPPs (Eastern Area)

199 1998 1 97 1 98 1999 2000 20

Approval by EG_ Board______________________________11111111111

TRA21SMSSSJON SYSTEI PLANNING DIVISION

5. POWER SYSTEM STUDIES

Power system studies have been made to investigate and verify the maximum

power transfer capability of the 500 kV transmission plan as recommended by the BVI/PTI

study. This revised study has been perforned with the changing conditions from the previous

BVIPTI study; i.e., the adoption of new load forecast and Power Development Plan (PDP

95-01); the generating capacity of the planned Ratchaburi Termal Power Plant is increased

from 3,600 MW to 4,600 MW; and the possibility of 600 MW stage I IPP Project to be

integrated at Ratchaburi 2 Substation. The 500 kV transmission plan is also adopted for the

connection of 10,000 MW power plant projects in the eastern area.

In the 1994 solicitation for power of 4,100 MW from IPPs, has included the first

1,000-1,300 MW (First Stage IPPs) for completion during 1996-2000. With the limitation

of the existing transmission capability, many substations have the capacities enough to

.ecei. the power from the first stage IPPs with the maximum of:

either 600 MW at Ratchaburi or 800 MW at Sam Phran for the western area,

and either 700 MW at Ao Phai or 700 MW at Pranchin Buri or 300 MW at

Khlong Mai and 200 MW at Rayong for the eastern area.

For the next 2,800 MW of capacity, preference will be given to a division of

approximately 1,400 MW located in the westem area and 1,400 MW located in the eastern

area in order to stabilize the power system.

According to the recommended plan in the PDP 95-01, the power development

program during 1998-2011 includes many new large base-load power plants and the power

purchases from the IPPs as follows:

IPP 1,300 MW (without system reinforcement) 1998-2000

Ratchaburi Combined Cycle (3x600 MW) 1998-1999

Ratchaburi Thernal Plant (4x700 MW) 1999-2001

-31-

IPP (2x700 MW) 2001

IPP (2x700 MW) 2002

IPP (1,000 MW) 2003

IPP (1,000 MW) 2004

IPP & EGAT new thermal plant (2xl 000 MW) 2005

IPP & EGAT new thermal plant (2x 000 MW) 2006





IPP & EGAT new thermnal plant (2x1000 MW) 2011

As shown above, up to 2011, the large base load power plant projects of about

13,100 MW will be given to IPPs and the other new power plants for a total capacity of

11,600 MW will be developed by EGAT.

For the studies, all of the first stage IPPs (1,300 MW) of the 1994 solicitation are

assumed to be located in the Western and Eastern Areas at the limited capacity of each

substation. However, for the next and future IPPs, including the new EGAT thermal power

plant projects as indicated in the PDP 95-01, two basic plans are used for the studies: (1)

All future power plants are assumed to be located in the west coast for the studies of the

transmission system in the Western Area; and (ii) All future power plants are assumed to

be located in the east coast for the studies of the transmission system in the Eastern Area.

Steady state power flow and stability studies are simulated at both peak load and

light load conditions to determine the maximum power transfer capability of the proposed

4 circuits of the 500 kV transmission lines. Fault level study is also carried out.

The following machine parameters ate used in the study.

Inertia constant of each generator (iH) = 3.8 kW-s_VA

Transient reactance (Xd) = 0.28 p.u.

Subtransient reactance (X"d) = 0.22 p.u.

-32-

Auto transformer impedance (500/230 kV) = 22 0/a

Short-circuit impedance of generator transformer = 18 %Power factor = 0.85

All exciters are equipped with power system stabilizers (PSSs)

5.1 The 500 kV Transmission System in the Western Area

Two double-circuit 500 kV transmission lines, using 4x1272 MCM ACSRconductors per phase, from Bang Saphan to Chom Bung switching station and from Chom

Bung to Wang Noi and Sai Noi in the Bangkok vicinity have been planned. The latter linesections will be constructed under Ratchaburi Power Plant Project.

The generated power, totalling 4,600 MW, from the Ratchaburi combined cycle

power plant and the Ratchaburi thermal power plants, as well as 600 MW of the first stageof IPP installed at Ratchaburi 2 Substation, are assumed to be included in Year 2000.

With the completion of the proposed 500 kV iines by the end of Ye 2000, theresults of the studies can be concluded as follows:

a) System of Year 2001 with additional 2x700 MW IPP Power Plants

(total 1.400 MW)

From the power system analyses, it is shown that the system works technicallysatisfactorily.

b) System of Year 2002 with additional 2x700 MW IPP Power Plants (total

accumulative new caDacities from Year 2001 is 2.800 MW)

With the samne configuration, the system is technically satisfactory.

c) System of Year 2003 with additional 1.000 MW IPP Power Plant (totalaccumulative new capacities from Year 2001 is 3.800 MW)

The system is technically satisfactory without any reinforcement.

-.33 -

d) System of Year 2004 with additional 1 000 MW IPP Power Plant (total

accumulative new capacities from Year 2001 is 4.800 MW)

The system studites based on the N-! critprinn confirm th the svytem i

technically viable. If, however, the N-2 is applied on the 500 kV Chom Bung - Sai Noi line

during the light load period, the system is oscillated (Figure Case TS-LO4W). To solve such

problem, the sectionalization of one circuit of the 500 kV Chom Bung - Wang Noi line and

the reconnection of the two line sections at the 500 kV Sai Noi Substation is proposed.

e) System of Year 2005 with additional 1,000 MW IPP and 1,000 MW new

thermal Power Plant (total accumulative new capacities from Year 2001 is

6-800 MM

Transient stability studies based on the N-1 criterion show that the system isunstable if a three phase fault occurs on the 500 kV Bang Saphan - Chom Bung line during

light load period (Figure Case TS-LO5W). flowever, if only 1,000 MW Power Plant is

included this year, the system is technically satisfactory with both N-I and N-2

contingencies..

Based on the results of the study, it can be concluded that the maximum

power transfer capability of two double-circuit 500 kV lines from Bang Saphan to ChomBung can be 5,800 MW. To increase the power transfer capability, the addition of more

parallel lines or the installation of the appropriate series compensators are required. Further

studies will be carried out for the next stage of transmission system reinforcement or

expansion program.

Power flow diagrams and stability curves are shown in Appendix 2 and 3.

5.2 The 500 kV Transmission System in the Easem Area

Two double-circuit 500 kV lines consisting of one double-circuit from

Rayong 4 to Wang Noi and another double-circuit from Rayong 4 to Nong Chok, using

4xi272 MCM ACSR conductors per phase, are assumed in the studies. The integration with

the existing system is made at Rayong 4 by the installation of two 500/230 kV tie

-34-

transformers, each rated 1,000 MW, connecting to Rayong 2 Substation via a 230 kV

double-circuit line, using 4x1272 MCM ACSR conductors per phase.

Since it is possible to add 700 MW out of the first iPP into the Eastem Area, theinjection of 300 MW in Khlong Mai and 400 MW in Ao Pha is assumed in this study. This

case is considered as the worst scenario to the network conditions.

The results of the studies can be concluded as follows:

a) System of Year 2001 with additional 2x700 MW IPP Power Plants (totalaccumulative new caDacities from Year 2001 is 1.400 MW)

With the proposed 500 kV transmission system, the system is technicallysatisfactory.

b) Svstem of Year 2002 with additional 2x700 MW IPP Power Plants (total

accumulative new capacities from Year 2001 is 2.800 MW)

With the same system configuration above, the system is technicallysatisfactory.

c) System of Year 2003 with additional 1,000 MW IPP Power Plants(total accumulative new canacities from Year 2001 is 3.800 MW)

The system is technically satisfactory without any further reinforcement.

d) System of Year 2004 with additional 1.000 MW IPP Power Plants (total

accumulative new caoacities from Year 2001 is 4.800 MW)

From the power system analyses, it is shown that the system is still technicallysatisfactory.

-35-.

e) System of Year 2005 with additional 1.000 MW IPP and 1,000 MW new

thermal Power Plants (total accumulative new capacities from Year 2001 is6.800 MW)

The results of the studies show that the system is technically satisfactorywithout further reinforcement.

f) System of Year 2006 with additional 1.000 MW IPP and 1.000 MW new

thermal Power Plants (total accumulative new caRacities from Year 2001 is

8.800 MW)

The high fault current (exceed 50 kA) at 500 kV Rayong 4 was observed.

The measure to limit the fault current was the splitting of the 500 kV bus into two buses,

with equal capacity at each bus was used. But the power flow studies shew thfat, in ca-e of

N- I contingency, if a fault occured on the 500 kV Rayong 4 - Nong Chok line, the 500/230

kV tie transformer at Bus #1 of Rayong 4 would be 8 % overloaded during peak load

period, and if a fault occured on the 500 kV Rayong 4 - Wang Noi line, the 500/230 kV tie

transformer at Bus #2 of Rayong 4 would be overloaded about 18 % and 5 % during peak

and light load periods respectively. So that the installation of two additional 500/230 kV

tie transformers at Rayong 4 Substation will be recommended. No transient instability is

shown, when a disturbance occurs in the system.

g) System of Year 2007 with additional 1.000 MW IPP and 1.000 MW new

thermal Power Plants (total accumulative new caDacities from Year 2001 is

10.800 MW)

The power flow studies based on the single contingency criterion show that

the 230 kV Rayong 2 - Ao Phai line will be overloaded by 7.6 %, if a fault is applied on

each line.

The transient stability studies have been also investigated. The results

indicate that the svstem is unstable if a three-phase fault occurs on the 500 kV Rayong 4 -

Nong Chok line.

-36-

If only 1,000 MW Power Plant is connected to the system in this year, hneresults of the studies show that the system is still unstable, if a three-phase fault is appliedon one circuit of the 500 kV Rayong 4 - Wang Noi line during the light load period.

As the results of the study, the maximum power transfer capability of theEastern Area is 8,800 MW. Further studies are required to determine the additional transfercapability. The installation of more parallel lines or series compensators would berecommended in the next stage of transmission system expansion program.

Power flow diagrams and stability curves are shown in Appendix 2 and 3.

Conclulsion

For the 500 kV transmission system in the Western Area, the maximum powertransfer capability of the two 500 kV double-circuit line is 5,800 MW by the stability limit.

For the 500 kV transmission system in the Eastern Area, the maximum powertransfer capability of the two 500 kV double-circuit transmission line is 8,800 MW by thestability limit.

To increase more power transfer capability of the two areas, further studies willbe required. According to the BVI study, the installation of more 500 kV lines or theinstallation of series capacitor with appropriate compensation would be the options to beconsidered.

5.3 Fault Level Studies

The fault level studies have been conducted for the development of the Western

500 kV transmission system and the Eastem 500 kV transmission system in Year 2005 and

2006 respectively.

The three-phase fault and the single-line-to-ground fault at the concerned power

plants and substations have been investigated. The high fault current is observed at 500 kV

Rayong 4 Busbar in 2006. This is due to the fact that many generating units will be

installed. To limit the fault current at this power plant, splitting the bus at the switchyard

into two sections would be therefore recommended in 2006. The expected high fault

current at significant power plants and substations (with the measures to limit fault currents)

are shown below:

-37-

5.3.1 The Development of the Western 500 kV Transmission Lines

3-0 (kA) 1-0 (klA

230 kV South Thon Buri Substation 40.5 28.0

230 kV Bangkok Noi Substation 44.0 26.7

230 kV Wang Noi Substation 38.8 41.8

500 kV Bang Saphan Substation 34.0 30.5


5.3.2 The DeveloRment of the Eastern 500 kV Transmission Lines

3-0 (kA) 1-0 (kA)

230 kV On Nuch Substation 41.6 25.0


230 kV Rayong 2 Substation 42.0 39.0

230 kV Bang Pakong Substation (Bus #1) 39.9 45.1

230 kV Bang Pakong Substation (Bus #2) 47.1 48.0

230 kV Rayong 4 Substation 46.9 42.1

500 kV Rayong 4 Substation (Bus #1) 29.9 33.0

500 kVRayong 4 Substation (Bus #2) 29.6 33.0


Fault current flow diagrams are shown in Appendix 4.

Notes 3-0 = three-phase fault.

1-0 = single-line-to-ground fault.

-38-

6. ECONOMIC ANALYSIS

The economic analysis is made to justify the economic viability of the proposed500 kV transmission system. The proposed 500 kV transmission system project is

compared with the other transmission project which can transmit the bulk power from theIPP plants to the load center. Referring to BVI/PTI study, two out of three basic systemshave been reviewed: the 500 kV transmission system (the preferred plan) and the 765 kV

transmission system (The second best alternative).

The requirement of transmission system for the 765 kV alternative are determined

to meet the same maximum transfer capability of the 500 kV alternative.

The cost streams of the two altematives which comprise the capital investment

cost, operation and maintenance cost (O&M) and the cost of system losses are compared by

U-sxng disoCunt csh flow technique. Trhe benefit/cost ratio (B/C ratio), net present value

(NPV) with reference to 10 % discount rate and the equalized discount rate (EDR) arecalculated to indicate the least cost alternative. The study is conducted separately for

westem and eastern coast IPP.

6.1 Transmission System Altemative

The transmission system alternatives for the west and east coast power plant

projects (IPPs as well as EGATs future base load power plant projects) can be summarized

as follows:

The West Coast

500 kV Alternative

- Construction of 500 kV Bang Saphan Substation.

-39-

- Construction of two routes of the 500 kV double circuit line from Bang

Saphan to Chom Bung, using 4x1272 MCM ACSR conductors. The distance of the two line

routes are approximately 275 and 280 km respectively.

- Expansion and improvement of the related substations.

765 kV Alternative

- Construction of 765 kV Bang Saphan and Chom Bung Substations.

- Construction of three circuits of 765 kV Bang Saphan - Chom Bung,

consisting of one double circuit steel tower line and one single circuit steel tower line. The

tiree circuits are strung wihm 4x1590 MCM ACSR conductors, a distance of approximately

285 km.

- Installation of 765/500 kV tie transformers at Chom Bung Substation,

rated 1,000 MVA, in the stages as required by the demand of the power system.

- Expansion and improvement of the related substation.

The East Coast

500 kV Alternative

- Construction of 500 kV Rayong 4 Substation.

- Construction of two routes of the 500 kV double circuit line from the

proposed new 500 kV Rayong 4 Substation to interconnect with Sai Noi (Wang Noi) - Nong

Chok transmission line, using 4x1272 MCM ACSR conductors with the distance of

approximately 155 and 170 km for the first and second line routes respectively.

- Construction of 230 kV double circuit line Rayong 4 - Rayong 2 using

4x1272 MCM ACSR conductors with the distance of approximately 10 km.

-40-

- Expansion and improvement of the related substations.

765 kV Alternative

- Construction of new 765 kV Rayong 4 Substation.

- Sectionalization and extension of two circuit of 500 kV Wang Noi -

Nong Chok to be terminated at the junction located 17 kan away from 500 kV Nong Chok

Substation and construction of the new 765/500 kV substation at the junction.

- Construction of three circuits of 765 kV Rayong 4 - New Substation.

consisting of one double circwut steel tower line and one single circuit steel tower line. The

ree circuits are strung with 4xl 590 MCM ACSR conductors, a distance of approximately

155 km.

- Construction of 230 kV double circuit line Rayong 4 - Rayong 2 using

4x1 272 MCM ACSR conductors with the distance of approximately 10 km.

- Installation of + 1,800 MVAr. Static Var Compensator (SVC) at new

substation.

- Installation of 765/500 kV tie transformers at new substation, rated

1,000 MVA, in the stages as required by the demand of the power system.

6.2 Capitl Cost of Alternatives All capital cost are estimated based on 1995 price

level. The cost without import duties and taxes, interest during construction (IDC) and

escalation are used in the analysis. The economic capital cost of two altemnatives can be

summarized as follows:

-41-

Unit: MTHB

Transmission Substation Total

LineWestem Transmission System

500 kV Altemative 10,625.0 3,938.5 14,563.5765 kV Alternative 11,428.1 7,682.8 19,110.9

Eastern Transmission System

500 kV Altemative 6,562.1 1,968.0 8,530.1765 kV Altemative 6,198.1 12,059.4 18,257.5

6.3 Operation and Maintenance Cost (O&M) The O&M cost of the transmission

line portion is assumed to be I % of the capital investment cost while the O&M cost of

substation is assumed to be 2 % of the capital cost.

6.4 Losses in the Transmission System Since two alternatives produce different

losses to the power system, the difference in EGATs power system losses is also taken into

account in the least cost analysis. The capacity loss (MW) is adopted from the power flow

study of the respective alternative. The energy loss (GWh) is calculated from the capacity

loss and loss factor using the equations as follows:

Energy Loss Capacity Loss (MW) x 8.76 x Loss Factor

Loss Factor = 0.1 x (Load Factor) + 0.9 (Load Factor)2

The cost of losses used in the study are adopted from EGATs Long Run

Marginal Cost (LRMC) which is based on 1994 price level and is escalated to be 1995 price

as follows:

Cost of Capacity Loss = 3,117.3 THB/kW-yr

Cost of Energy Loss = 0.7402 THB/kWh

6.5 Economic Life The economic life of the transmission line and substation are

assumed to be 40 and 25 years respectively.

-42-

6.6 Results of the Least Cost Solution Study

a) Comparison of Present Value

P. V at 10 % DR. (MTHB)

Western System

500 kV 32,518.3

765 kV 34,237.6

Eastern System

500 kV 28,919.7

765 kV 32,674.5

b) Net Present Value, B/C Ratio and EDR.

Net P. V. B/C EDR.

(MTHB) Ratio (%)

Westem System

500 kV VS. 765 kV 1,719.3 1.0529 > 150.0

Eastern System

500 kV VS. 765 kV 3,754.8 1.1298 > 150.0

The results of the study have led to the conclusion that the construction of 500

kV transmission system to transmit bulk power from the IPP power plants and EGAT base

load power plants is the least cost alternative for both west coast and east coast transmission

systems.

The summary of the results of the least cost solution study and the cost stream

of each alternative are shown in Tables 6.1 to 6.6.

-43-

Table 6.1Summary of Results of Economic Analysis

Project Transmission System Project for IPP

Cost Stream 500 kV Transmission System for Western IPP

Benefit Stream 765 kV Transmission System for Western IPP

Discount Present Value Present Value B/C Present ValueRate of of Ratio of(%) Benefit Cost Net Benefit

4.00 66045.18 65119.70 1.0142 925.496.00 51853.61 50471.44 1.0274 1382.188.00 41694.44 40077.11 1.0404 1617.33

10.00 34237.61 32518.32 1.0529 1719.2812.00 28633.47 26892.21 1.0647 1741.2614.00 24328.12 22612.40 1.0759 1715.7216.00 20953.07 19290.41 1.0862 i662.6618.00 18258.27 16663.80 1.0957 1594.4720.00 16070.71 14551.83 1.1044 1518.8822.00 14268.41 12827.72 1.1123 1440.6924.00 12763.77 11400.93 1.1195 1362.8426.00 11492.79 10205.68 1.1261 1287.11

Equalized Discount Rate is Greater Than 150%

Transmission System Planning Division29-Jan-96

-44- 04:19 PM

Table 6.2Cost Stream of 500 kV Transmission System for Western IPP

Unit: MTHBFiscal Capital Cost O&M Cost Syste Losses Cost of Losses f TotalYear Line 1 Sub. Line Sub. Peak Energy Peak Energy Cost

1995 j 1 (GWh | .1996 12.2 110.0 i 122.21997 231.8 _ 231.81998 2633.6 41.7 2675.31999 5359.7 1320.1 I 6679.82000 1882.3 2105.6 3987.912001 505.4 361.1 106.3 78.8 376.05 1889,99 1172.3 1399.0 3622.82002 106.3 78.8 427.63 2158.42 1333.1 1597.7 3115.82003 106.3 78.8 481.37 2456.52 1500.6 1818.3 3504.02004 106.3 78.8 585.91 3052.17 1826.5 2259.2 4270.82005 106.3 78.8 602.40 3162.88 1877.9 2341.2 4404.12006 106.3 78.8 602.40 3187.79 1877.9 2359.6 4422.62007 1 106.3 78.8 602.40 3207.32 1877.9 2374.1 4437.02008, 1 106.3 78.8 602.40 3215.15! 1877.9 2379.9 4442.82009 106.3 78.8 602.40 3222.99 1877.9 2385.7 4448.62010 106.3 78.8 602.40 3230.05 1877.9 2390.9! 4453.82011 106.3 78.8 602.40 3237.12 1877.9 2396.1i 4459.12012 106.3 78.8 602.40 3237.12 1877.9 2396.1 4459.12013 iu6.3 ,. eo2.4 2-37.12 1877.9 2396.1 4459.12014 106.3 78.8 602.40 3237.12 1877.9 2396.1 4459.112015 106.3 78.8 602.40 3237.12 1877.9 2396.1 4459.12016 106.3 78.8 602.40 3237.12 1877.9 2396.1 4459.12017 106.3 78.8 602.40 3237.12 1877.9 2396.1 4459.12018 106.3 78.8 602.40 3237.12 1877.9 2396.1 4459.12019 106.3 78.8 602.40 3237.12 1877.9 2396.1 4459.12020 106.3 78.8 602.40 3237.12 1877.9 2396.1 4459.12021 106.3 78.8 602.40 3237.12 1877.9 2396.1 4459.12022 106.3 78.8 602.40 3237.12 1877.9 2396.1 4459.12023 106.3 78.8 602.40 3237.12 1877.9 2396.1 4459.12024 106.3 78.8 602.40 3237.12 1877.9 2396.1 4459.12025 -3984.41 - 106.3 78.8 602.40 3237.12 1877.9 2396.1 474.7

Total 6640.6 3938.5 2657.5 1970.0 - 1 45267.4 57247.1 117721.2P.V. 7067.8 2544.2 599.1 444.1 - - 97082 12154.9 32518.3

10% DR. I I I I__III__

-45-

Table 6.3Cost Stream of 765 kV Transmission System for Western IPP

Unit: MTHB

Fiscal Capital Cost O&M Cost System Losses Cost of Losses TotalYear Line Sub, Line Sub. Peak Energy Peak Enorgy Cost

(MW) (GWh)l

19951996 12.2 110.0 122.21997 345.8 _ 345.81998 3626.7 56.5 3683.21999 5144.3 1984.1 7128.42000 1817.4 3097.8 4915.22001 481.7 974.1 114.3 124.5 374.55 1882.46 1167.6 1393.4 4255.62002 511.9 114.3 134.7 418.65 2113.09 1305.1 1564.1 3630.12003 453.9 114.3 143.8 463.16 2363.59 1443.8 1749.5 3905.32004 445.7 114.3 152.7 552.14 2876.25 1721.2 2129.0 4562.92005 48.8 114.3 153.7 554.13 2909.44 1727.4 2153.6 4197.82006 114.3 153.7 554.13 2932.36 1727.4 2170.5 4165.92007 114.3 153.7 554.13 2950.32 1727.4 2183.8 4179.22008 114.3 153.7 554.13 2957.52 1727.4 2189.2 4184.52009 114.3 153.7 554.13 2964.73 1727.4 2194.5 4189.92010 114.3 153.7 554.13 2971.23 1727.4 2199.3 4194.72011 114.3 153.7 554.13 2977.73 1727.4 2204.1 4199.52012 114.3 153.7 554.13 2977.73 1727.4 2204.1 4199.52013 114.3 153.7 554.13 2977.73 1727.4 2204.1 4199.52014 114.3 153.7 554.13 2977.73 1727.4 2204.1 4199.52015 114.3 153.7 554.13 2977.73 1727.4 2204.1 4199.52016 114.3 153.7 554.13 2977.73 1727.4 2204.1 4199.52017 114.3 153.7 554.13 2977.73 1727.4 2204.1 4199.52018 114.3 153.7 554.13 2977.73 1727.4 2204.1 4199.52019 114.3 153.7 554.13 2977.73 1727.4 2204.1 4199.52020 114.3 153.7 554.13 2977.73 1727.4 2204.1 4199.52021 114.3 153.7 554.13 2977.73 1727.4 2204.1 4199.52022 114.3 153.7 554.13 2977.73 1727.4 2204.1 4199.52023 114.3 153.7 554.13 2977.73 1727.4 2204.1 4199.52024 114.3 153.7 554.13 2977.73 1727.4 2204.1 4199.52025 -4285.5 - 114.3 153.7 554.13 2977.73 1727.4 2204.1 -86.0

Total 7142.6 7682.8 2857.5 3783.4 - - 41912.8 52988.7 116367.7P.V. 7690.1 4653.2 644.2 835.0 - _ 9068.1 11347.0 34237.6

10% DR.] _ .

-46-

Table 6.4summary of Results of Economic Analysis

Project Transmission System Project for IPP

Cost Stream 500 kV Transmission System for Eastem IPP

Benefit Stream 765 kV Transmission System for Eastern IPP

Discount Present Value Present Value B/C Present ValueRate of of Ratio of(O) Benefit Cost Net Benefit4.00 66339.75 62399.89 1.0631 3939.866.00 51200.26 47163.03 1.0856 4037.238.00 40469.28 36524.66 1.1080 3944.62

10.00: 1 2674.4B 28919.65 1A1298 3754.8112.00 26880.44 23359.48 1.1507 3520.9614.00 22480.44 19207.23 1.1704 3273.2216.00 19072.64 16044.36 1.1887 3028.2918.00 16385.55 13590.54 1.2057 2795.0120.00 14232.06 11654.45 1.2212 2577.6122.00 12480.82 10103.13 1.2353 2377.6924.00 11037.86 8842.S3 1.2483 2195.3226.00 9834.83 7805.05 i.260I 2029.78

Equallzed Discount Rate is Greater Than 150%

Transmission System Planning Division29-Jan-96

04:23 PM-47-

Table 6.5Cost Stream of 500 kV Transmission System for Eastem IPP

Unit: MTHBFiscal Capltal Cost O&M Cost System Losses Cost of Losses TotalYear une Sub. Line Sub. Peak Energy Peak Energy Cost

(MWv) (GWh)

19951996 7.2 220.0 227.21997 136.2 - 136.21998 1561.5 28.4 1589.91999 3321.9 555.7 3877.62000 1217.3 1000.3 2217.62001 317.9 163.6 65.6 39.4 396.11 1990.81 1234.8 1473.6 3294.92002 65.6 39.4 403.34 2035.81 1257.3 1506.9 2869.22003 65.6 39.4 426.62 2177.12 1329.9 1611.5 3046.42004 65.6 39.4 490.54 2555.36 1529.2 1891.5 3525.62005 65.6 39.4 539.60 2833.15 1682.1 2097.1 3884.22006 65.6 39.4 663.96 3513.56 2069.8 2600.7 4775.52007 65.6 39.4 663.96 3535.08 2069.8 2616.7 4791.42008 65.6 39.4 663.96 3543.71 2069.8 2623.1 4797.82009 65.6 39.4 663.96 3552.35 2069.8 2629.4 4804.22010 65.6 39.4 663.96 3560.13 2069.8 2635.2 4810.02011 65.6 39.4 663.96 3567.93 2069,8 2641.0 4815.72012 65.6 39.4 663.96 3567.93 2069.8 2641.0 4815.72013 65.6 39.4 663.98 3567.93 2069.8 2641.0 4815.72014 65.6 39.4 683.96 3567.93 2069.8 2641.0 4815.72015 65.6 39.4 663.96 3567.93 2069.8 2641.0 4815.72016 65.6 39.4 663.96 3567.93 2069.8 2641.0 4815.72017 65.6 39.4 663.96 3567.93 2069.8 2641.0 4815.72018 65.6 39.4 663.96 3567.93 2069.8 2641.0 4815.72019 65.6 39.4 663.96 3567.93 2069.8 2641.0 4815.72020 65.6 39.4 663.96 3567.93 2069.8 2641.0 4815.72021 65.6 39.4 663.96 3567.93 2069.8 2641.0 4815.72022 65.6 39.4 663.96 3567.93 2069.8 2641.0 4815.72023 65.6 39.4 663.96 3567.93 2069.8 2641.0 4815.72024 65.6 39.4 663.96 3567.93 2069.8 2641.0 4815.72025 - 240.8 _ 65.6 39.4 663.96 3567.93 2069.8 2641.0 2355.0

Total 4101.3 1968.0 1640.0 985.0 - _ 48428.5 61300.41 118423.2P.V. 4355.5 1314.3 369.7 222.1 - _ 10053.3 12604.7 28919.7

10% DR. ... .. ...

-48-

Table 6.6Cost Stream of 765 kV Transmission System for Eastern IPP

Unit: MTHB

Fiscal Capital Cost O&M Cost Svstem Losses Cost of Losses TotalYear Line Sub. Line Sub. Peak Energy Peak Energy Cost

(MW) (GWh)

19951996 7.2 550.0 557.21997 203.0 _ 203.01998 2071.3 71.2 2142.51999 2535.7 1664.7 4200.42000 1130.5 3119.0 4249.52001 250.4 944.4 62.0 127.0 401.19 2016.35 1250.6 1492.5 4126.92002 120.4 62.0 129.4 390.02 1968.58 1215.8 1457.1 2984.82003 405.1 62.0 137.5 416.46 2125.27 1298.2 1573.1 3476.02004 969.1 62.0 156.9 474.24 2470.45 1478.3 1828.6 4495.02005 3768.9 62.0 232.3 505.46 2653.90 1575.7 1964.4 7603.32006 446.6 62.0 241.2 582.77 3083.91 1816.7 2282.7 4849.22007 62.0 241.2 582.77 3102.81 1816.7 2296.7 4416.62008 62.0 241.2 582.77 3110.38 1816.7 2302.3 4422.22009 62.0 241.2 582.77 3117.96 1816.7 2307.9 4427.82010 62.0 241.2 582.77 3124.79 1816.7 2313.0 4432.82011 62.0 241.2 582.77 3131.63 1816.7 2318.0 4437.9

.2012 62.0 241.2 582.77 3131.63 1816.7 2318.0 4437.92013 62.0 241.2 582.77 3131.63 1816.7 2318.0 4437.92014 62.0 241.2 582.77 3131.63 1816.7 2318.0 4437.9,2015 62.0 241.2 582.77 3131.63 1816.7 2318.0 4437.92016 62.0 241.2 582.77 3131.63 1816.7 2318.0 4437.92017 62.0 241.2 582.77 3131.63 1816.7 2318.0 4437.92018 62.0 241.2 582.77 3131.63 1816.7 2318.0 4437.92019 62.0 241.2 582.77 3131.63 1816.7 2318.0 4437.92020 62.0 241.2 582.77 3131.63 1816.7 2318.0 4437.92021 62.0 241.2 582.77 3131.63 1816.7 2318.0 4437.92022 62.0 241.2 582.77 3131.63 1816.7 2318.0 4437.92023 62.0 241.2 582.77 3131.63 1816.7 2318.0 4437.92024 62.0 241.2 582.77 3131.63 1816.7 2318.0 4437.92025 -2324.3 - 62.0 241.2 582.77 3131.63 1816.7 2318.0 2113.6

Total 3873.8 12059.4 1550.0 5607.1 - - 43152.1 54689.0 120831.3P.V. 4172.5 6431.6 349.4 1150.0 - _ 9132.9 11438.0 32674.5

10% DR. . _ _ _ _ _

-49-

7. FINANCIAL JUSTIFICATION OF THE PROJECT

The financial justification is the economic and financial internal rate of return(MU DD FIRA oTtDD he 500 kAV 1,,, -"',"' -ystem f"r the wvest ct anfd east

coast IPP power plants by comparing their investment costs with the benefit accrued from

the project. The study is made separately jor EIRR and FIRR study.

7.1 Economic Internal Rate of Return Study (EIRR)

The economic internal rate of return study is conducted by comparing the cost

of impletnenting the 500 kV transmission system of both west coast and east coast systems

with the benefit which will be made available from the purchasing of electric energy from

the IPP together with the electric energy generated from EGAT's coal-fired power plants

which are planned to be connected to the proposed 500 kV transmission system. Details of

IPP and EGATs power project planned to be connected.to the proposed project are shown

in Table 7.1. The cost and benefit applied for the study will be the combined cost and

benefit of the west coast and east coast systems since the projects are proposed to be

implemented simultaneously.

The benefit of the project for the EIRR study can be pointed out by two

approaches, i.e;

Aporoach 1 : The benefit of the project is assumed to be the reduction of the

countrys load losses and outages. The load losses will be presented as the difference in the

probabilistic Expected Unserved Energy (EUE) between the EGAT's Power Development

Plan (PDP) with and without the project calculated by using Westinghouse Interactive

Generation Planning Software (WIGPLAN) computer program. The cost of the reduction

of the EUE resulting from the implementation of this project is adopted from the latest

"EGATs Cost of an Outage Study" conducted by EGATs System Planning Department on

October 1992. The cost of an outage according to the mentioned study is 58.87 THB/kWh.

-50-

3' -

Approach 2 : Since the proposed 500 kV transmission system project is

proposed to transmit bulk power from the IPP and EGAT's coal-fired power plants to the

load center in the central region, so it is reasonable to assume that the benefit of the project

is the incremental energy sale resulting from the implementation of this project.

7.1.1 Basic Assumptions

The economic internal rate of return (EIRR) study of the two approaches

are performed based on the following assumptions:

Cost Stream The cost stream of the projects consists of the following

a) Capital Investment Cost The capital investment cost is the

construction cost of the 500 kV transmission system implemented for west coast and east

coast systems. The constant 1995 price without import duties and taxes, interest during

construction (IDC) are used for the stud.v

b) Operation and Maintenance Cost (O&M) The O&M of the project

are also assumed to be the percentage of the capital cost as used in the economic analysis.

c) Cost of Energv Supply The purchasing price between EGAT and

IPP is assumed as a cost of supplying electric energy of both IPP and EGATs coal-fired

power plants. Since the real purchasing price is still unknown at the time of the study, the

forecasted purchasing price is adopted from EGATs financial projection which are

conducted based on EGATs PDP 95-01 for the period of 1995-2001. The levelized nominal

purchasing price (current value) at Year 2001 is 1.6040 TUB/kWh.

Benefit Stream The assumptions used for the calculation of benefit

stream are:

Aooroach I The benefit is assumed to be the incremental economic

benefit of the country due to the reduction of expected load losses which may occurred if theproposed project is not implemented. The Expected Unserved Energy (EUE) is used to

represent these losses and the cost of an outage of 58.87 THB/kWh is used to calculate themonetary value of these losses.

-51-

Approach 2 The benefit is assumed to be the incremental energy sale

made available to EGAT by this project. The calculation of the benefit is based on the

assumptions as follows:

a) Incremental Energv Sale The value of the incremental energy sale

is calculated from the energy produced by the IPP reduced by the losses in transmission

system. The losses are represented in term of energy loss occurring between the sending end

and the receiving end of the proposed transmission line. The energy loss (GWh) is

calculated from the capacity loss (adopted from the power flow study) and IPP's plant factor

as follows:

Energy Loss (GWh) = Capacity Loss (MW) x 8.76 x Plant Factor

b) Averaze Sellinz Price The EGAT average selling price is adopted

from EGATs financial analysis of the Year 2001 which is adjusted to conform with all of

the required financial criteria.

7.1.2 Sensitivitv Study

Due to the uncertainty of the purchasing price from IPP, EGATs average

selling price and other economic paramneters of the project, the sensitivity studies of EIRR

study based on the variation the project's vital economic parameters are also conducted to

examine the effect of these variations to the EIRR of the project. The sensitivity study is

calculated according to the variation of the economic parameters as follows:

- The purchasing price from IPP.

- The EGAT's average selling price.

- Capital investment cost of the project.

- Expected unserved energy.

-52-

7.1.3 Results of the EIRR Study

The results of the base case and sensitivity study can be summarized as

follows:

a) Base Case

EIRR (%)

- Approach 1 107.01

- Approach 2 22.63

b) Sensitivity Studv

A_Mroach I

EIRR (%/6)

- Purchasing Price

-Increased by 10 % 106.95

- Increased by 20 % 106.89


- Capital Cost

- Increased by IO % 104.62



- EpxDected Unserved Enersv

- Decreased by 10 % 104.37



Approach 2

- Purchasing Price



-53-

EIRR (%)

- Capital Cost

- Increa-ed lw 10 % :21.42



- Average Selling Price



It can be concluded from the results of the base case calculation of EIRR that the

project is economically feasible and the sensitivity studies indicate that for Approach 1, the

EIRR is not sensitive to the tested variation but for Approach 2, the EIRR is sensitive to the

increment of the purchasing price and the decreasing of EGAT's average selling price.

Details of the base case calculation of EIRR of the two approaches are shown Table 7.2 and

7.3.

-54-

Table 7.

IPP and EGATs Power Project Planned to be Transmitted

via the Proposed 500 kV Transmission System

Power Plant Fuel Unit Rating Cumulative Commissioning

Type Number (MW) Capacity Date

*_____ ___ :___ ___ (MW)

IPP - - 1,400 1,400 April 2001

IPP - - 1,400 2,800 April 2002

IPP - - 1,000 3,800 January 2003

IPP - - 1,000 4,800 January 2004

IPP - - 1,000 5,800 January 2005

New Thermal Coal 1 i1,000u 6,800 Arii 2005

IPP -- 1,000 7,800 January 2006

New Thermal Coal 2 1,000 8,800 April 2006

IPP - - 1,000 9,800 January 2007

New Thernal - 3 1,000 10,800 April 2007

IPP - - 1,000 11,800 January 2008


IPP - - 1,000 13,800 January 2009


-s5 -

Table 7.2Calculation of EIRR of 500 kV Transmission System for IPP (Approach 1)

unil: MTHSFiscal al_ _ Cost Stream ... b/ Benefit Stream NetYear Capita Cost O&M Cost Supplied Purchasing Price Cost Total Expected Jnserved En rgy (GWh) Cost of Project Benefit

Lire Substation Line Substation Energy (THB,l of Cost W/O 500 kV Wth 500 kV EUE Outages Benefit(GWh) Current 1995 Supply Transmission Transmission Reduction (THB/k'Wh)

____ _____ ______ _______ Price Price _ roject o/ Prope,t cl1995 1996 19.4 330.0 - 349.4 -349.41997 368.0 _- - 368.0 -368.01998 4195.1 70.1 _ - 4265.2 -4265.21999 8681.6 1875.8 _ - 10557.4 -10557.42000 3099.6 3105.9 - d/ - 6205.5 -6205.52001 823.3 524.7 171.9 1182 1.5 1.6040 1.2677 2.0 1640.1 1.55 _ 1.5 5s.87 91.1 -1549.02002 - - 171.9 118.2 19.3 1.6040 1.2677 24.5 314.6 19.32 19.3 55.87 1137.3 822.72003 171.9 118.2 534.1 1.6040 1.2677 677.1 967.2 534.12 534.1 55.87 31443.4 30476.22004 171.9 118.2 1238.9 1.6040 1.2677 1570.5 1860.6 1238.86 1238.9 53.87 72931.7 71071.12005 171.9 118.2 7303.3 1.6040 1.2677i 9258.1 9548.2 7303.27 7303.3 53.87 429943.6 420395.4u' 2006 171.9 1182 17352.8 1.6040 1.2677 21997.5 22287.6 17352.75 17352.8 53.87 1021556.4 999268.8

' 2007 i 171.9 1182 24934.0 1.6040 1.2677 31607.9 31698.0 24933.981 24934.0 53.87 1467863.6 1435965.62008 ! 171.9 1182 40631.0 1.6040, 1.26771 51506.41 51796.5 40630.98 I 40631.01 513.87 2391945.5 2340149.020091 171.9 1182 54067.7 1.60401 1.2677 68539.7; 68529.5 54067.72 54067.71 513.87 3182966.9 3114137.12010\ 17i.9 11152 W202o 1 .5040 1 .267 81156.2 81446.3 64020.24 6402021 5!3.87 3768871.5 3687425.22011 i 171.91 1182 734s.020 1.60401 1.2677 93148.0 93438.1 73480.00 273480.0! 3.87 4325767.8 4232329.72012 1 171.91 118.2 73480.0 1.60401 1.2677 93148.01 93438.1 73480.00 73480.0'1 53.87 4325767.8 4232329.72013 171.9 118.2 73480.0 1.6040 1.2677 93148.01 93438.1 73480.00 73480.0 583.87 4325767.8 4232329.72014 | 171.9 1182 73480.0 1.6040 1.2677 93148.01 93438.1 73480.00 m 73480.0 583.87 4325767.8 4232329.72015 171.9 1182 73480.0 1.6040 1.2677 93148.0 93438.1 73480.00 j 1 7348.00 58.87 4325767.8 4232329.72016 171.9 118.2 73480.0 1.6040 1.2677 93148.0 93438.1 73480.00 73480.0 593.87 4325767.8 4232329.72017 171.9 118.2 73480.0 1.6040 1.2677 93148.0 93438.1 73480.00 73480.0 513.87 4325767.8 4232329.72018 171.9 1182 73480.0 1.6040 1.2677 93148.0 93438.1 73480.00 73480.0 s53.87 4325767.8 4232329.72019 171.9 1182 73480.0 1.6040 1.2677 93148.0 93438.1 73480.00 73480.0 513.87 4325767.8 4232329.72020 171.9 118.2 73480.0 1.6040 1.2677 93148.0 93438.1 73480.00 73480.0 513.87 4325767.8 4232329.72021 171.9 1182 73480.0 1.6040 1.2677 93148.0 93438.1 73480.00 73480.0 513.87 4325767.8 4232329.72022 171.9 118.2 73480.0 1.6040 1.2677 93148.0 93438.1 73480.00 73480.0 513.87 4325767.8 4232329.72022 171.9 1182 73480.0 1.6040 1.2677 93148.0 93438.1 73480.00 73480.0 513.87 4325767.8 4232329.72024 171.9 1182 73480.0 1.6040 1.2677 93148.0 93438.1 73480.00 73480.0 563.87 4325767.8 4232329.72025 -6445.1 _ 171.9 1182 73480.0 1.6040 1.2677 93148.0 86993.0 73480.00 73480.0 513.87 4325767.8 4238774.Total 10741 .! 5906.5 4297.5 2955.0 _- _ - t6e3559.71 1687460J3 I - - 77255268.0 755678072

Economic Internal Rate of Return = 107.01%Notes: a/ Capital investment cost of western and eastem 500 kV transmission system for IPP. Transmission System Phnnng Oivision

bf Probabilistic unserved energy calculated by using WIGPLAN . 30-Jan-9g6J/ Adopted from 'Cost of an Outage Study, by EGAT's System Planning Department (October 1992).41 Adoptecl from EGAT's Financial Projection (1 995-2001) and assumed to be constant alter 2001.2/ Incremental EUE.

Table 7.3Calculation of EIRR of 500 kV Transmission System for IPP (Approach 2)

Fiscal Cost _S_r_e Unit :MIHBFiscal __________ Cosit Stream ______ Benefit Stream NoetYewt Can 1 Cost O&M Cost Cost of Energy Supply Total Poweor Energy Energy Average SelOing Price Revenue BenefitUine Substailotn Une Substation Planned Plnned PurchasIng Price Cost C t Loss Loss Sale (IHB*WhI

Power Energy (THB/ kWh) of : ;; U(MW) (GWh) (GWh) Current 1995Purchase Purchase Currert 1995 Supply PHice Price

W (SHlh) Price P.e ' _ :' _ :___

1995 _ _

1996 19.4 330.0 349.4 _ -34941997 368.0 _ 368.0 -358.01998 4195.1 70.1 4265.2 _ -4265.21999 8681.6 1875.8 10557.4 -410557.42000 3039.6 9105.9 1 1 6205.5 _ - -6205.52001 823.3 524.7 171.9 118.2 1400 4600.0 1.6040 1.2677 5831.3 7469.4 8.4 589 4541.1 1.8478 1.4603 6631.6 -837.82002 - - 171.9 118.2 2800 13800.0 1.6040 1.2677 17493.8 17783.9 32.4 227.1 13572.9 1.8478 1.4603 19821.2 2037.32003 171.9 118.2 3800 23330.0 1.6040 1.2677 29574.6 29864.7 58.0 406.5 22923.5 1.8478 1.4603 33476.2 3611.52004 171.9 11 82 4800 29900.0 1.6040 1.2677 37903.2 38193.3 95.0 665.8 29234.2 1.8478 1.4603 42692.0 4498.7120051 171.9 118.2 6800 39755.0 1.6040 1.2677 50396.0 50688.1 134.6 943.3 38811.7 1.8478 1.4603 56678.4 5992.311 20066 i e t171.9 118.2, 8800 52895.0 1.6040 1.2677 67053.1 67343.2 243 1t698.3 5t196.7! 1.8478' 1:4603 74764.8; 7421.620071 I 171.9 118.2 10800 66035.0 1.6040 1.2677: 83710.2' 84000.3 242.3 1698.3 64336.71 1.84781 1.4603 93953.7 9953.42008i 171.91 118.2| 12800 79175.0 1.60401 1.26771 100367.3 100657.4 242.31 1698.31 77476.7 1.8478', 1.4603 113142.6. 12485.2'20091 171.9! 118.2, 14800 92315.0! 1.60401 1 2677 ! 117024.4 117314.5 242.3! 1698,31 90616.7, 1.8478' 1.4603 132331.5 15017.0!2010, 171.91 118.21 148D0 97240.01 1.50401 1.2677 123267.7, 12S557.8 242.3 1698.3, 95541.7: 1.8478j 1.4603 139523.7 15965.9120111 17191 118.21 14800 97240.01 1.6040i 1.2677, 123267.71 123557.8 242.3| 1698.3, 95541.7 I 1.84781 1.4603 139523.7 15965.92012 171.91 118.2j 14800 97240.0 1.60401 1.2677' 123267.71 123557.8 242.3 1698.3 95541.7 1.84781 1.4603 139523.7 15965912013 171.91 118.2 14800 97240.0 1.6040 1.2677 123267.7 123557.8 242.3 1698.31 95541.7 1.84781 1.4603 139523.7 15965.92014 171.9 118.2 14800 97240.0 1.6040 1.2677 123267.7 123557.8 242.3 1698.3 95541.7 1.8478 1.4603 139523.7 15965.912015 171.9 118.2 14800 97240.0 1.6040 1.2677 123267.7 123557.8 242.3 1698.3 95541.7 1.8478 1.4603 139523.7 15965.92016 171.9 1182 14800 97240.0 1.8040 1.2677 123267.7'| 123557.8 242.3 1698.3 95541.7 1.8478 1.4603 139523.7 15965.92017 171.9 118.2 14800 97240.0 1.6040 1.2677 123267.;' 123557.8 242.3 1698.3 95541.7 1.8478 1.4603 139523.7 15965.92018 171.9 11&2 148O0 97240.0 1.6040 1.2677 123267.7 123557.8 242.3 1698.3 95541.7 1.8478 1.4603 139523.7 15965.92019 171.9 118.2 14800 97240.0 1.6040 1.2677 123267.7 123557.8 242.3 1698.3 95541.7 1.8478 1.4603 139523.7 15965.92020 171.9 118.2 14800 97240.0 1.6040 1.2677 123267.7 123557.8 242.3 1698.3 95541.7 1.8478 1.4603 139523.7 15965.92021 171.9 1182 14800 97240.0 1.6040 1.2677 123267.7 123557.8 242.3 1696.3 95541.7 1.8478 1,4603 139523.7 15965.92022 171.9 118.2 14800 97240.0 1.6040 1.2677 123267.7 123557.8 242.3 1698.3 95541.7 1.8478 1.4603 139523.7 1596592023 171.9 118.2 14800 97240.0 1.6040 1.2677 123267.7 t23557.8 242.3 1698.3 95541.7 1.8478 1.4603 139523.7 15965.92024 171.9 118.2 14800 97240.0 1.6040 1.2677 123267.7 123557.8 242.3 1698.3 95541.7 1.8478 1.4603 139523.7 15965.92025 -6445.1 - 171.9 118.2I 14800 97240.0 1.60401 1.26771 123267.71 117112.7 242.3 1698.3 95541.7 1.8478 1.4603 139523.7 22411.0

Total 10741.9 5906.51 4297.51 2956.0 - - - - | 248163711 2505538.0 --- | 28058711.2 300333.21Economic Internal Rate of Retum = 22.63 _J

Noe: al Adopted from EGAr5 Financial Projection (1995- 200t) and assumed to be constant after 2co1. Traismission Sys:em Planning Drvs,on

30-Jan- 96

7.2 Financial Internal Rate of Retum Study (FIRR)

Apart from the intemal rate of return study based on the country's point of view,

the intemal rate of return of the project based on EGAT's point of view is also conducted to

evaluate the financial viability of this project. According to the purpose of the project as

previously mentioned, the 500 kV transmission system project is proposed to transmit the

bulk power to EGATs load center which is resulting in the increment of EGAT's energy

sale. So the financial intemal rate of return (FIRR) which is EGAT's rate of return from this

project is made by comparing the total cost of the project with the benefit from the

incremental revenue.

7.2.1 Basic Assumptions

The financial intemal rate of return study is performed based on theassumptions similar to the Approach 2 of the EIRR study. But all costs are based on their

current values including import duties and taxes, interest during construction (IDC).

7.2.2 Sensitivity Study

The sensitivity study of the FIRR study is also conducted as done for theEIRR study of which the assumptions are:

- The purchasing price from IPP is assumed to be increased by 5 and10%.

- The EGATs average selling price is assumed to be decreased by 5 and

10%.

-58-

7.2.3 Results of the FIRR Study

The results of the base case and sensitivity study can be summarized asfollows

FIRR (%)

a) Base Case 22.23

b) Sensitivity Study

- Purchasing Price



- Capital Cost

- Increased by 10 2!.03

- Increased by 20 %XO 19.96

- Increased by 30 % 19,00

- Average Selling Price


- Decreased by 1 0 3.24

It can be noticed from the results of the base case calculation of FIRR that theproject can generate the internal rate of return to EGATs acceptable level while the

sensitivity study shows that the FIRR is not sensitive to the change of project's investment

cost but sensitive to the variation of the purchasing price and average selling price since the

10 % variation of these values can make the FIRR dropped below EGAT's acceptable level.

Details of the base case calculation of the FJRR is shown in Table 7.4.

59-

Table 7.4Calculation of FIRR of 500 kV Transmission System for IPP

L)r,_t M rH13Fiscal Cost Stream -Benefit Stream NetYear Capi1al Cost O&M Cost Cost of Energy SuPPlY Total Power Energy Energy Average Sellirng Price Revenue Benefit

Une Substation Line Substatbon Planned Planned Purchasing Price Cost cost Loss Loss Sale _CB/1W1Power Energy (THB/kWh) of (MW) (GWh) (GWh) Current 1995

Purchase Purchase Current 1995 Supply Price Price______ ________ ) (GWh) Price Price _________ ._______ ________ ________ ___G__e_ _ __ __

1995 - - _ _1996 44.1 366.6 410.;r - -410.71997 424.7 1 38.8 463.5 -463.51998 4852.4 120.0 4972.4 _ - 4972.41999 11444.7 2352.7 13797.4 _ - -13797,42000 4938.2 4228.2 o/ 9166.4. _ - -9166.42001 1055.4 604.2 227.6 154.2 1400 4600.0 1.6040 1.2677 7378.4 9419.8 8.4 58.9 4541.1 1.8478 1.4603 8391.1 1028.72002 - - 227.6 154.2 2800 13800.0 1.6040 1.2677 22135.2 22517.0 32.4 227.,1 13572.9 1.8478 1.4603 25080.1 2563 12003 227.6 154.2 3800 23330.0 1.6040 1.2677 37421.3 37803.1 58.0 406.5 22923.5 1.8478 1.4603 42358.1 4555.02004 227.6 154.2 4800 29900.0 1.6040 1.2677 47959.6 48341.4 95.0 665.8 29234.2 1.8478 1 .4603 54019 0 5677 62005 227.6 154.2 6800 39755.0 1.6040 1.2677 63767.0 64148.8 134.6 943.3 38811 7 1.8478 1.4603 71716.31 7567.52006 227.6 154.2 8800 52895.0 , 1.6040 1.2677 84843.6 85225.4 242.3 1698.3 51196.7 . 1.8478 1.4603 94601.3 9375.92007 227.6 154.2 10800 66035.01 1.6040 1.2677| 105920 1 106301.9 242.3 1698.3 64336.7 1.8478 1.4603 1118881.41 12579.42008| ! 227.6 154.2 12800 79175.0| 1.6040 1.2677 126996.7| 127378.5 2423 16983 77476.7 1.84781 1.4603 143161.4 15782.92009 ! 6 227.6 154.2 14800 92315.01 1.6040 1.2677 148073.31 148455.1 242.3| 1698.3 90616.7 A.84781 t.4603 167441.5 18986.52010 227.61 154.2| 14800 97240.01 1.6040 1.2677 155973.01 156354.8 242.31 1698.3 95541.7 1.8478 1.4603 176542.01 20187.22011 227.6 154.2 14800 97240.01 1.6040 1.2677, 155973.01 156354.8 242.31 1698.3 95541.7! 1.8478 1.4603 176542.0 2018722012 227.6 154.2 14800 97240.0) 1.6040 1.26771 155973.0 156354.8 242.31 1698.3 95541.71 1.84781 1.4603 176542.0 20187.22013 i 227.6 154.2 14800 97240.0 1.6040 1.2677 155973.0! 156354.8 242.3j 1698.3 95541.7 1.8478j 1.4603 176542.01 20187.2;2014 227.6 154.2 14800 97240.0 1.6040 1.2677 155973.0| 156354.8 242.3' 1698.3 95541.7 1.84781 1.4603 176542.01 20187212015 227.6 154.2 14800 97240.0 1.6040 1.2677 155973.0 156354.8 242.31 1698.3 95541.7 1.8478, 1,4603 176542.0| 2018722016 227.6 154.2 14800 97240.0 1.6040 i.2677 155973.01 156354.8 242.3 1698.3 95541.7 1.8478 1.4603 176542.0 20187.22017 227.6 154.2 14800 97240.0 1.6040 1.2677 155973.0 156354.8 242.3 1698.3 95541.7 1.8478 1.4603 176542.0 20187.22018 227.6 154.2 ,14800 97240.0 1.6040 1.26771 155973.0 156354.8 242.3 1698.3 95541.7 1.8478 1 4603 176542.0 | 20187 22019 227.6 154.2 14800 97240.0 1.6040 1.2677 155973.0 156354.8 242.3 1698.3 95541.7 1.8478 1 4603 176542.0 20187.22020 227.6 154.2 14800 97240.0 1.6040 1.2677| 155973.0 156354.8 242.3 1698.3 95541.7 1.8478 1.4603 176542.0 20187.212021 227.6 154.2 14800 97240.0 1.6040 1.2677 155973.0 156354.8 242.3 1698.3 95541.7 1.8478 1.4603 176542.0 20187 2| 2022| l l 227.6 154.2 14800 97240.0 1.6040 1.2677 155973.01 156354.8 242.3 1698.3l 95541.7 1.8478 1.4603 176542.0 20187.22023 227.6 154.2 14800 97240.0 1.6040 1.2677 155973.01 156354.8 242.3 1698.31 95541.7 1.8478 1.4603 176542.0, 2018722024 227.6 154.2 14800 97240.0 1.6040 1.2677 1559730 156354.8 242.3 1698.3 95541.7 1.8478 1.4603| 176542.0 2018722025 -8534.8 - 227.6 154.2 14800 97240.0 1.6040 1.2677 155973.0 147819.9 242.31 1698.3 95541.7 1.8478 1.4603 176542.0 28722.0

Total 14224.| 7710.5 5690.0 3855.0 - - - - 3140062.63175428 -j- -L -- 3550321 Sl 378778.8tFinancial Internal Rate of Return = 22.23% _

Note a/ Adopted from EGAT's FRnancial Projection (1995-2001) and assumed to be constant after 2001. Irarism,ss,on SysternPOrrnngDv,s,onG7 - Dr - 99

8. SHUNT REACTOR SIZING

8.1 Objective and Method of Study

Two shunt reactors of equal magnitude are installed at each end of an extra high-voltage transmission line to compensate for the Ferranti Effect. Ferranti Effect is a

phenomenon that the voltage at the receiving end of a long open-ended uncompensated

transmission line is higher than at the sending end for the steady-state condition. The

receiving-end voltage, VREc, can be roughly calculated by the following expression

VREC VSENDJCOS

where e is the line length and j is the phase factor, which is equal to approximately

7.20/100 km. The longer the transmission line is, the higher the Ferranti Effect becomes.

In the study, the size of the shunt reactor to be installeu at each end of thetransmission line is varied from 0-300 MVAr. The installation of shunt reactors has been

considered for the transmission lines which are longer than 150 km since the Ferranti Effect

on a shorter line is found to be nonsignificant.

Shunt reactors can also reduce the overvoltage during energization of

transmission lines but the amount of surge reduction is small compared to other more

practical counter-measures. The study has been conducted with the computer software

developed by Manitoba HVDC Research Center. The use of the software is under a trial

agreement between Manitoba HVDC Research Center and EGAT.

8.2 Results of Studv

The shunt reactor sizing study has been conducted for four 500 kV transmission

lines as follows:

1) Bang Saphan - Chom Bung

2) Wang Noi - Chom Bung

-61-

3) Rayong 4 - Wang Noi

4) Rayong 4 - Nong Chok

The overvoltage during line energization of the Bang Saphan - Chom Bung has

been found to be 1.046 p.u. For the other 3 lines, the overvoltages are less than 3 %

Nontheless, if shunt reactors were to be installed to compensate for the Ferranti Effect, the

following are the reactors which would reduce the receiving end voltages to 1.0 p.u.

1) 150 MVAr/phase for Bang Saphan - Chom Bung lines

2) 100 MVAr/phase for Wang Noi - Chom Bung lines

3) 105 MVAr/phase line Rayong 4 - Wang Noi lines

4) 82.5 MVAr/phase line Ravong 4 - Nong Chok lines

The results of the reactor sizing study are shown in Figure 8.1 to Figure 8.4. Samples of the

switching transients for the Bang Saphan - Chom Bung lines are also shown in Figure 8.5

to Figure 8.7.

-62-

FIGURE 8.1REACTOR SIZING FOR BANG SAPAN - CHOM BUNG LINES

(280 KM)1.05

1.04

g 1.03 _

| 1.02

0\

1.01

o 0.99

0.9 8 ..............

~0.97

0.96

,150 MVAR

0.95 I , I I I0 50 100 150 200 250 300 350

REACTOR SIZE (MVAR)

-63-

FIGURE 8.2REACTOR SIZING FOR WANG NOI - CHOM BUNG LINES

(192 KM)1.051

1.04

1.03

1.02

1.01

ZF-

0.99

00.98

O0.97

0.96

100 MVAR

0.95 I i I I I I0 50 100 150 200 250 300 350

REACrOR SIZE (MVAR)

-64-

FIGURE 8.3REACrOR SIZING FOR RAYONG 4 -WANG NOI LINES

(210 KM)1.05

1.04

1.03

1.02

Q \0

1.01_ . .. X... . ..........

o0.99

00.98

0.97

0.96

-105 MVAR

0.95 I I l l0 50 100 150 200 250 300 350

REACTOR SIZE (MVAR)

-65-

FIGURE 8.4REACTOR SIZING FOR RAYONG 4- NONG CHOK UNES

(172 KM)* 1.05I

1.04

1.03

| 1.02

1.01

0.99

0 0.98

0.97

0.96

:82.5 MVAR

0.95 I I I i I I0 50 100 150 200 250 300 350

REACTOR SIZE (MVAR)

-66-

o Voltage at Bang Saphan Phase A (tanient) o Voltage t BaU Saphan Phae A (stady tate)2.5

2. 1.5 -.. ____.. _._ __.___.__._.-_ ...-.-.--.-.... g.__.___. ..... ___._. -- ---- ------ …----

0.5;F ~ ~ -_ _ __. _ _ _ _ . _ _ .

0 o a !7... -. .- ----

0.5 . .____ ** *f-------

-2 -_ . --------t----.---- - - - -- __..

-2.5 1480 500 520 540 560

Time (sec) xio3

O Voltage at Bang Sapban Phae B (transient) 0 Voltage at Bang Sapbhn Phasw 3 (shady state)2.5 -

2 ------ _ _ -1--..---..-.- ........ . .......------1.5 _ ___--- ------- - --- - ~ ---,,, ------ __

AIA~~~~~~~~~~~~ > 1 ,,___.4..___~~~~~~~~~~~~~~~~~~--- - --- *----t,t5

0 -0OI o -- M-- -M---q- -+-e-f-

° ..2 .L ......-------- - ------ …

480 SOO 520 540 SO

Time (sec) x104

Ol Voltage at Bang Saphan Pbhe C (tansient) 0 Volta at Bang Sapban Pae C (shdy state)2.5 -

2 … . …____---------.. t

--1 - - --------- An------

.5 0.5 o-… -A --- , …-... _. -_

0

-1.5 …--- -- - --------- .

-0.--…-2---. -----. ….--- .

-2.5 480 500 520 540 560

Time (sec) x104

Pigure 8.5 Energization of Chom Bung- Bang Saphan Lines (wf 150 MVAr Reactors)

(Energize from Cbom Bung)-67-

0 Voltage at Chom Bung Phase A (transient) 0 Voltage at CBG Phase A (steady ste)2.5

> -1_ _~_ ___________ ;_. _ ..-.-..----.--- .-. ~.-................................................. .. ........ .............

-1 .5 ........-... ...-. ....................; 0 5 --- ---- --s- t-t- -...-........... --- -- --- ---- - -- - - ---2 ----2 ..-- * -----...-...- ________.__-__ -_______

-2.5 -480 soo 520 540 560

Time (sec) X104

O Voltage at Chom BURn Pbae B (ti.nent) a Voltage at CRC P B a(smlY Ate)2.5

2 --.- -.-.---..-....-.. .- .. ..... ....... .-.- - - -1.5 -.-.� ._... ........... .............. . .. ...........

-1 O . ....... ...... _ ..__..._ . _ _ ...... _._.-; -1 -. -----.--. ------ -. ._.... .... _.._.____....----------------- - ------ -_.

-12 ........... ............... ... .... . ..... .

-2.5480 500 520 540 560

Time (sec) x104* 1

O Voltage at Chom Bung Phase C (transient) 0 Voltage at CBG Phase C (stedy stae)

2.5 12 ....................... .......................... ..... ..... . --

1 0.5 . _ _ .-. .... … .__........…. _ .\1 -. ..- .... ~~~~~~~~~~~~~~~~~...............---'-15 _ __ _ _............ .... _ _ _ _______ _ _

0

-2 --- -----------------

-2.5 . . . . .

480 500 520 540 560

Time (sec) x2103

Figure 8.6 Energization of Chom Bung - Bang Saphan Lines (w/ 150 MVAr Reactors)

(Energize from Bang Saphan)-68-

0 Voltage at Bang Saphan (with reactors) 0 Voltage at Bang Sapban (wio react)2.5 T

2 --- -________ _.._ .... 4... ..

10.5 .._.__._.______ r- 6g-.A [email protected] .~..__J_.-_. 415 *--..- -= -- -. .-.-.-- ------- -- -

0.5 *..

o 2 -- ._ __ ----.----- . .-------.. _-2.5 J I

480 500 520 640 50

Time (sec) x104

O Voltage at Bang Sapban (with reactor) 0 Voltage t Bang Sphan (wlo reactorv)2.5 1.56 - -,

1.5 *--. Phse-- .-V--.--.------- ---

I.s _ Phj... B .. ........- ............ .. ___.__

480 500 520 540 560

Time (icc) xlO'

O Voltage atBang Saphan (with reactors) 0 Voltage at Bang Saphan (w/o racton)2.5

2 --- Ph0 e-C ................... ..

1.5 - --------- - --- -I

0 .5 _ _ . _. ...._.__.--F''---t-'t---f _

0-

-o-2- ---- t------.- --

-2 _. ..... _.__. __._.__.._.____...........~....._.__.._______._…_

-2.5480 soo 520 540 560

Time (sec) X103

Figure 8.7 Comparison of Overvoltage for Chom Bung - Bang Saphan Lines

(Energize from Chom Bung)-69-

REFERENCES

1. EGAT's System Planning Department. EGAT Power DeveloDment Plan (PDP 95-01).Report No.21200-3802, April, 1995.

2. Black & Veatch International Company. Feasibility Study for Transmissiion SystemDevelopment for Southern Power Plant Proiect, July, 1994.

-70-

APPENDIX I

SUBSTATION LOAD FORECAST

-71-

I I

ADDendix IPage 1

Substation Load Forecast of Metropolitan Area

COINCIDENT____________________ UNIT: MW

ACT1AL . FTORECAST

SUBSTATION 1994 1997 1998 1999 2001 2006 2011(25. (2540) (2541) (2542) (2544) (2549) (2554)

BANG KAPI 69 KV 617.40 565.03 543.34 570.11 599.06 724.31 763.74

BANG KAPI 230 KV (CL) 421.80 348.21 345.25 355.43 387.49 282.51 270.50

BANG KAPI 230 KV (KT) 0.00 0.00 0.00 0.00 377.41 629.52 666.80

BANG PHLI 69 KV 301.00 175.55 197.01 202.83 213.55 321.22 358.09

BANG PHLI 115 KV 331.70 509.31 394.78 368.97 424.06 342.09 359.13

BANGKOK NOI 69 KV 415.60 355.26 417.23 428.96 475.12 395.17 440.52

BANGKOK NOI 115 KV 0.00 50.85 50.93 66.97 97.70 303.08 342.72

CHAENG WATTANA 115 KV 0.00 249.35 340.60 463.98 670.74 656.61 720.73

LAT PHRAO 69 KV 574.00 536.86 605.01 606.01 420.13 714.04 730.80

NONG CHOK 115 KV i77.60 212.58 188.80 208.20 269.72 334.43 450.58

NORTH BANGKOK 69 KV 391.851 494.67 502.39 558.26 548.94 498.65 534.40

NORTH BANGKOK 2.30 KV 0.M 0.00 0.00 0.00 0.00 510.72 1,025.00

ON-NUCH 230 KV 0.00 0.00 178.84 247.02 296.83 544.74 804.32

ON-NUCH 230 KV (PK) 0.00 0.00 0.00 0.00 0.00 0.00 679.38

RANGSIT 69 KV 205.70 275.45 282.02 264.45 209.87 368.51 367.11

RANGSIT 115 KV 92.90 136.20 137.66 177.44 259.22 275.81 285.26

RATCHADA PHISEK 69 KV 0.00 354.65 365.99 394.85 355.67 346.67 359.80

RATCHADA PHISEK 115 KV 0.00 0.00 0.00 0.00 0.00 115.88 313.06

SAI NOI 115 KV 0.00 25.29 27.53 28.32 131.32 306.77 341.97

SOUTH BANGKOK 69 KV 620.20 495.82 517.92 528.50 607.02 630.86 703.27

SOUTH BANGKOK 115 KV 269.60 262.20 198.49 187.66 244.72 196.98 164.05

SOUTH THONBURI 69 KV 335.40 374.52 372.60 405.07 462.68 463.60 455.63

SOUTH THONBURI 230 KV 0.00 446.66 549.56 608.43 726.32 1,088.94 1,553.44

TEPARAK 69 KV 0.00 180.77 205.33 221.07 207.16 256.28 351.78

TEPARAK 115 KV 0.00 155.86 248.52 281.50 305.32 335.42 373.92

TOTAL 4,754.75 6,205.09| 6,669.80 7,174.03 8,290.05 10,642.81 13,416.00

-73-

AmDend ix 1Page 2

Substation Load Forecast of Central Area

NON- COINCIDENTUNIT: MW

_______________ ______________ _ __ _ _ __ __, _ _ _ _ _ _ ( 5 ) (2 4 ) _ _ _ACTUAL FORECASTSUBSTATION 1994 1997 1 1998 1999 2001 2006 2011(2537) Aqi4p 4 2541 (2.S42) (54 (2549) (2554l

ANGTHONG 1 14.31 14.63 14.75 14.89 15.19 16.21 17.68ANGTHONG 1 (69 KV) 0.00 10.20 10.20 10.20 10.20 10.20 10.20ANGTHONG 2 25.69 38.80 42.72 46.79 55.44 80.22 112.36AYUTTHAYA 1 53.76 38.80 42.56 46.59 55.46 82.81 118.22AYUTTHAYA 2 13.38 18.52 20.32 22.24 26.47 39.53 56.42BANG PA-IN 1 39.12 44.36 48.57 53.03 62.79 92.74 132.04BANG PA-IN 1 (115 KV) 25.49 36.68 40.50 44.44 52.88 77.81 105.49BANG PA-IN 2 178.40 327.14 355.60 381.54 435.69 581.82 744.03CHAIBADAN 24.48 16.10 17.46 18.75 21.19 27.02 33.59DOEMBANG NANGBUAT 21.58 32.93 35.26 37.69 42.92 58.66 79.50LOP BURI 1 36.70 29.80 31.93 34.13 38.73 51.86 68.37LOP BURI 2 19.03 28.44 30.47 32.56 36.96 49.49 65.25LOP BURI 2 (115 KV) 0.00 12.20 13.75 15.30 15.30 15.30 15.30NAKHON NAYOK 24.58 19.74 21.49 23.31 27.21 38.77 53.42PHRAPHUTTHABAT 36.10 50.52 56.07 61.78 73.68 107.39 152.17RANGSIT (69 KV) 213.46 264.08 286.05 307.95 353.07 491.36 679.59RANGSIT (115 KV) 219.74 264.08 286.05 307.95 353.07 491.36 679.59SAI NOI (115 KV) 0.00 55.58 59.97 64.63 74.86 106.99 151.58SARABURI 1 44.40 52.57 .57.15 61.96 72.51 105.86 152.82SARABURI 2 35.85 25.53 27.93 30.44 35.88 52.58 75.75SARABURI 2 (115 KV) 179.23 255.29 298.11 331.84 361.74 370.26 382.33SARABURI 3 96.06 95.00 95.00 95.00 95.00 95.00 95.00SARABURI 4 35.96 63.62 68.28 73.25 84.23 118.95 168.00SARABURI 4 (115 KV) 11.82 18.30 18.30 18.30 18.30 18.30 18.30SINGBURI 33.50 33.95 36.47 39.04 44.26 58.84 77.11SINGBURI (115 KV) 0.00 16.00 16.00 16.00 16.00 16.00 16.00SUPHAN BURI 43.88 31.12 33.84 36.72 43.04 62.79 90.17THALAN 1 26.38 35.79 37.53 39.34 43.18 .54.11 67.10THALAN 1 (115 KV) 95.94 10.10 10.10 10.10 10.10 10.10 10.10THALAN 3 (115 KV) 0.00 263.03 276.70 289.35 312.96 372.82 436.46THALAN I (CEMENT) 57.82 60.00 60.00 60.00 60.00 60.00 60.00THALAN 2 (STEEL) 53.36 115.00 115.00 115.00 115.00 115.00 115.00PHACHI (VOA) 2.45 2.50 2.50 2.50 2.50 2.50 2.50

TOTAL 1,662.47 2,380.40 2,566.63 2,742.61 3,065.81 3,932.65 5,041-44

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Ap2end i x 1Page 3

Substation Load Forecast of Eastern Area

NON- COINCIDENTUNIT: MW

ACTUAL FORECAST

SUBSTATION 1994 . 1997 1998 1999 2001 2006 2011_2537) _ (2540) (2541) (2542) (2544) (2549) (2554)

AO PHAI 29.35 12.40 13.35 14.36 16.67 23.88 33.83

AO PHAI (115 KV) 53.60 173.26 187.85 199.94 226.27 305.79 412.61

BAN BUNG 49.62 58.01 65.07 72.53 88.95 139.99 207.15

BAN BUNG (l15KV) 0.00 21.87 27.98 29.86 29.86 29.86 29.86BANG LAMUNG 55.69 66.21 71.78 77.68 90.55 130.41 185.27

BANG LAMUNG (115 KV) 28.27 43.69 47.36 51.25 59.75 86.05 122.25

BOWIN (115 KV) 64.20 169.70 181.61 192.22 209.84 256.97 291.77

CHACHOENGSAO 98.84 62.28 68.3 74.41 87.64 127.83 181.74

CHACHOENGSAO (115 KV) 0.00 0.00 0.00 0.00 0.00 0.00 0.00

CHANTHABURI 65.08 51.73 56.41 61.30 71.85 104.65 149.95

CHANTHABURI (115 KV) 0.00 49.24 53.57 58.10 67.91 98.36 140.37

CHOM THIEN 23.64 33.48 35.65 37.94 42.96 58.47 79.83

CTH ON BUDIT 76.64 31.22 33.90 36.72 42.85 61.62 87.11

KHLONG MAI (115 KV) 120.00 238.45 257.11 276.57 317.i7 438.3 605.12

KLAENG .38.84 30.18 32.53 35.01 40.45 5728 80.36

PRACHIN BURT 1 53.56 28.91 30.96 33.16 38.02 53.47 75.06

PRACHIN BURI 2 0.00 9.47 10.14 10.86 12.45 17.51 24.58

PRACHIN BURI 2 (115 KV) 0.00 115.56 139.12 157.80 199.60 300.45 388.56RAYONG 1 45.14 44.49 49.07 53.86 64.13 94.98 137.77

RAYONG 1 (115 KV) 44.64 0.00 0.00 0.00 0.00 0.00 0.00RAYONG 2 23.09 26.59 28.61 30.75 35.43 49.75 68.98

RAYONG 2 (115 KV) 92.01 402.79 463.42 485.62 514.49 57.15 634.51

RAYONG 3 50.60 42.24 46.80 51.38 61.02 90.78 132.27

SI RACHA 28.44 32.44 34.47 36.58 41.16 55.26 7428

TRAT 26.50 25.91 27.36 28.85 32.00 40.97 51.92

TRAT (115 KV) 0.00 6.16 6.50 6.86 7.60 9.74 12.34

WATTHANA NAKHON 29.66 27.17 29.43 31.80 36.98 52.95 74.74

WATTHANA NAKHON (115 KV) 0.00 13.35 14.46 15.62 18.17 26.01 36.71

AO PHAI (THAI OIL) 42.64 50.00 50.00 50.00 50.00 50.00 50.00

AO PHAI (ESSO CO. PLANT) 7.31 3.80 3.80 3.80 3.80 3.80 3.80SATTAHIP I (DIR) 8.27 10.00 10.00 10.00 10.00 10.00 10.00SATTAHIP 2 (DIR) 22.69 31.96 34.89 37.86 43.96 57.52 69.77

TOTAL 1,178.32 1,912.56 2,111.43 2,262.69 2,561.53 3,404.85 4,452.51

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ADDendix 1Page 4

Substation Load Forecast of Western Area

NON- COINCIDENT______________ _____ _UNIT: MW

ACTUAL FORECAST 1SUBSTATION 1994 1997 1998 1999 2001 2006 ' 2011

.2537) (2540) (2541) (2542) (2544! (25491 t2ss*

BANPONG 1 91.60 .50.36 55.32 60.37 70.79 100.62 140.96

BANPONG 2 66.16 34.53 35.53 36.61 38.99 46.65 57.53

BANPONG 2 (115 KV) 0.00 49.26 50.77 52.38 55.96 67.45 83.77

BANG SAPHAN 47.00 17.16 18.60 20.07 23.06 26.17 41.17

BANG SAPHAN (115 KV) 0.00 135.00 135.00 135.00 135.00 135.00 135.00

CHA AM 40.84 35.22 38.07 40.94 46.88 62.84 82.22

HUA HIN 0.00 29.97 32.36 34.78 39.83 54.02 71.57

KAMPHAENG SAEN 30.71 40.44 43.53 46.84 54.17 77.73 111.26

KAMPHAENG SAEN (115 KV) 26.81 0.00 0.00 0.00 0.00 0.00 0.00

KANCHANABURI 43.48 59.03 63.18 67.55 77.06 106.17 145.60

KANGKRACHAN 0.00 0.00 0.00 0.00 0.00 0.00 0.00

KHAO LAEM 4.83 5.00 5.17 5.35 5.71 6.76 8.06

NAKHON CHAISI 124.74 117.19 126.74 136.91 159.25 229.08 325.83

PHETCHABURI 30.76 42.89 46.34 49.86 57.14 76.26 96.38

PRACHUAP KHIRI KHAN 26.20 20.15 21.84 23.56 27.07 36.64 48.33

PRANBURI 25.66 17.63 19.01 20.43 23.40 32.05 42.90

RATCHABURI 1 21.54 31.90 34.34 36.85 42.13 56.80 73.44

RATCHABURI 2 33.56 26.13 28.64 31.20 36.47 50.35 66.70

RATCHABURI 2 (115 KV) 0.00 60.46 66.16 71.99 84.67 117.84 161.67

SAM PHRAN 1 113.30 82.79 89.31 96.29 111.70 160.88 231.02

SAM PHRAN 1 (115 KV) 0.00 291.22 314.26 338.57 391.44 555.34 784.40

SAM PHRAN 2 87.84 75.68 81.74 88.20 102.50 148.02 212.88

SAMUT SAKHON 1 87.80 53.16 57.75 62.66 73.53 108.09 157.08

SAMUT SAKHON 2 73.76 103.87 112.70 122.09 142.79 208.20 300.07

SAMUT SAKHON 2 (115 KV) 12.92 26.15 29.97 34.08 43.12 70.00 103.54

SAMUT SAKHON 3 82.12 69.48 75.38 81.68 95.59 139.60 201.53

SAMUT SONGKHRAM 36.16 25.65 27.58 29.58 33.85 46.36 62.48

SkRNAGARINu 0.60 0.69 0.74 0.79 0.89 1.16 1A9

THA MUANG (PEA) 28.56 31.17 33.22 35.40 40.20 55.21 75.75

TOTAL 1,136.95 1,532.18 1,643.25 1,760.03 2,013.19 2,775.29 3,822.63

-76-

Apoendi x IPage 5

Substation Load Forecast of Northeastern AreaNON - COINCIDENT

__._._. UNIT: MWi ACTUAL FORFCAST

SUBSTATION 1994 1997 1998 1999 2001 2006 2011_ 25-37) 1 (2540) (2541) (2542) (2544) (2549) (2554)

AMNATCHAROEN .00( 17.41 18.85 20.32 23.40 32.21 42.25

BAN PHAI 16.88 24.66 26.69 28.80 33.33 46.94 65.35BAMNETNARONG 0.00 0.00 36.80 38.10 40.80 47.79 55.40

BUNG KAN 15.96 10.96 11.78 12.62 14.39 19.19 24.76BURI RAM 55.88 20.52 21.92 23.34 26.19 34.08 43.82CHAIYAPHIUM 37.68 40.66 36.80 39.75 44.51 60.29 80.74CHAIYAPHUM (115 KV) 000 5.81 6.22 6.64 7.55 10.20 13.56CHULABHORN 0.00 0.15 0.16 0.18 0.21 0.31 0.43CHUM PHAE 37.47 39.34 42.22 45.19 51.44 68.92 89.26KALASIN 36.80 29.23 31.28 33.39 37.88 50.23 64.80KANTARALAK (.00 0.00 19.90 21.70 25.30 35.60 45.45KHONG 28.20 24.29 26.74 29.26 34.54 49.78 69.40KHONG (115 KV) (.00 34.65 39.29 40.70 43.59 51.52 60.92KHON KAEN 1 48.96 61.84 66.70 71.79 82.61 113.30 148.90KHON KAEN 2 25.12 32.51 35.07 37.75 43.44 59.57 78.29LOEI 33.44 23.15 24.93 26.75 30.40 40.69 52.91LOEI (115 KV) 0.00 8.62 9.29 9.96 11.35 15.16 19.71MAHA SARAKHAM 37.24 36.33 38.57 40.87 45.69 59.48 76.66MUKDAHAN (PEA) * 18.54 24.03 26.22 28.46 33.07 45.74 60.15NAKHON PHANOM (PEA) 15.18 19.58 21.10 22.72 26.27 37.37 52.50NATKHON RATCHASIMA 1 75.95 28.92 43.17 45.58 50.49 61.97 80.43NAKHON RATCHASIMA 2 44.00 59.40 43.17 45.58 50.49 61.97 80.43NAKHON RATCHASIMA 2 (115 KV) 3.60 58.91 66.73 73.88 85.63 123.35 165.65NAM PHONG 25.31 22.71 24.67 26.65 30.72 41.87 55.36NAMPHONG(115 KV) 19.43 40.30 41.43 42.59 44.98 51.58 59.30NAM PHUNG 2.64 4.03 4.49 4.96 5.97 9.1D 13.43NONG BUA LAM PHU 0.00 30.43 32.59 34.79 39.30 51.82 66.52NONG HAN 14.02 17.54 18.67 19.83 22.24 28.64 36.81NONG HAN (115 KV) 6.45 8.50 8.50 8.50 8.50 8.50 8.50NONG KHAI 27.10 35.67 38.57 41.64 48.24 68.31 94.83PAK CHONG 34.48 43.68 46.84 50.13 57.13 77.45 102.92PHAYAKKHAPHUM PHISAI 0.00 25.41 27.11 28.85 32.40 42.32 54.57PHAYAKKHAPHUM PHISAI (115 KV) 0.00 12.75 13.60 14.46 16.18 20.89 26.68PHANG KHON 20.36 22.92 24.53 26.23 29.86 40.51 53.62PHANG RHON (115 KV) 0.00 7.31 7.85 8.42 9.60 12.79 16.51PHON 19.88 26.02 27.96 29.99 34.36 47.03 62.04PHON THONG 0.00 19.82 21.28 22.70 25.86 34.62 45.03PRAKHON CHAI 0.00 30.78 32.88 35.01 39.29 51.11 65.73ROI ET 40.76 57.35 61.84 64.67 74.43 101.93 134.20SAKHON NAKHON 25.30 33.28 35.98 38.86 45.21 65.09 92.64SANGKHA 0.00 0.00 15.30 16.80 20.00 28.80 39.90SI SA KET 49.40 54.73 36.25 38.87 44.86 63.11 87.01SIKHUI 35.20 42.11 43.00 45.56 51.04 67.27 87.96SIRINDHORN 8.61 10.94 11.85 12.78 14.65 19.72 25.78SOMDET 20.80 20.82 22.54 24.30 27.95 38.14 50.66SURIN 52.80 51.01 42.16 44.38 48.70 60.51 74.79THAT PHANOM 10.52 12.24 13.20 14.19 16.31 22.75 31.43UBON RATCHATHANI 1 49.80 50.33 53.67 57.14 64.47 85.32 111.33UBON RATCHATHANI 2 23.68 15.64 16.76 17.93 20.43 27.66 36.58UBON RATCHATHANI 2 (115 KV) 0.00 22.76 24.38 26.05 29.56 39.45 51.55UDON THANI 1 51.52 35.84 38.10 40.40 45.14 .58.09 73.14UDON THANI 2 26.88 35.85 38.10 40.40 45.14 58.09 73.14UDON THANI 2 (115 KV) 0.00 4.91 5.22 5.53 6.18 7.96 10.02YASOTHON 37.84 29.65 32.09 34.60 .39.84 54.84 71.94MUKDAHAN (SUVANNAKHET) 7.30 7.97 8.35 8.73 9.49 11.25 12.88NAKHON PHANOM (THAKHIIK) 4.20 5.05 5.25 5.45 5.85 6.85 7.85

TOTAL 1,145.18 1,419.32 1,568.61 1,674.72 1,896.45 2,529.03 3,306.42

-77-

ApDendix 1Page 6

Substation Load Forecast of Southern Area

NON - COINCIDENT

UNIT: MW

| ACTlAI, FORECAST | . n 1 -1979 1971 1970 ;99 2001 2v06 4

(2537) (254A 0__ (2541) (2542) (2544) (2549) (2554)

BAN DON 52.36 42.12 45.34 48.61 55.45 74.39 95.20

BANG LANG 5.92 8.66 9.40 10.15 11.66 15.74 20.54CHUMPHON 43.72 46.73 50.74 55.07 64.33 90.18 120.79HAT YAI 1 53.04 44.76 48.41 52.16 59.95 81.80 108.40HAT YAI 2 38.80 36.62 39.61 42.67 49.04 66.93 88.69HAT YAI 2 (115 KV) 0.00 44.09 57.15 66.61 85.07 112.75 136.58KAENG KRUNG 0.00 3.95 4.34 4.76 5.63 7.90 10.22KHANOM 30.24 33.84 36.44 39.10 44.67 60.99 81.37KHOK KLOI 0.00 5.36 7.05 8.33 9.35. 9.84 9.84KRABI 19.86 15.12 16.30 17.48 19.90 26.62 33.91KRABI (115 KV) 0.00 12.33 13.42 14.53 16.79 22.90 29.78LANG SUAN 0.00 11.68 12.69 13.77 16.08 22.55 30.20LAM POO RA 43.70 25.60 27.63 29.75 34.17 46.01 58.82LAM POO RA (115 KV) 0.00 31.29 33.77 36.36 41.77 56.23 71.88NAKHON SI THAMMARAT 66.56 67.82 73.31 78.90 90.35 121.77 160.16NAKHON SI THAMMARAT (115 KV) 0.00 19.13 20.68 22.26 25.49 34.35 45.17NARATHIWAT 31.80 17.56 18.89 20.28 23.19 31.38 40.66PATTANI 36.68 57.52 61.38 65.33 73.60 97.00 125.28PHANGNGA 15.80 10.65 11.65 12.73 14.77 20.46 27.17PHANGNGA (115KV) 0.00 4.56 4.99 5.45 6.33 8.77 11.65PHATTHALUNG 24.86 32.81 35.53 38.26 43.79 58.59 76.53PHUKET 1 44.00 40.05 43.37 46.84 54.25 76.53 105.76PHUKET 2 42.74 39.73 43.02 46.47 53.82 75.92 104.92PHUKET 2 (115 KV) 0.00 39.29 42.55 45.96 53.23 75.09 103.77PHUNPHIN 19.60 28.95 31.85 34.87 41.23 57.93 74.98RANONG 26.30 25.68 28.28 31.00 36.78 53.20 72.60RANONG (115 KV) 0.00 19.37 21.33 23.38 27.75 40.13 54.77RANOT 0.00 23.35 25.17 27.03 30.91 41.93 55.44RAJJAPRABHA 2.75 3.63 4.01 4.39 5.21 7.45 10.12SADAO 14.31 18.87 20.26 21.68 24.75 34.21 46.89SATUN 20.66 28.72 31.79 34.97 41.88 60.13 80.52SONGKHLA 64.08 63.14 68.04 73.09 83.58 113.36 149.88SUNGAI KOLOK 0.00 26.34 28.34 30.42 34.77 47.07 60.99TAKUA PA 11.92 13.30 14.23 15.19 17.23 23.27 30.91YALA 30.34 37.60 40.50 43.55 50.07 69.58 94.62THUNG SONG (PEA) 27.00 33.91 36.29 38.70 43.65 57.80 74.67THUNG SONG (PEA 115 KV) 0.00 15.58 16.77 17.98 20.50 27.52 35.21SADAO TO TNB 0.00 0.00 0.00 0.00 0.00 0.00 0.00THUNG SONG (CEMENT) 32.04 78.50 78.50 78.50 78.50 78.50 78.50

TOTAL 799.08 1,108.21 1,203.02 1,296.58 1,489.49 2,006.77 2,617.39

-78-

Appendix 1Page 7

Substation Load Forecast of Northern Area

NON- COINCIDENT_UNIT: MW

ACAL TORhCAST

SUBSTATION 1994 1997 1998 1999 2001 2006 2011(2537) (2540) 2541 2542 2544) (2549) (2554

BANG MUN NAK 0.00 34.00 36.65 39.34 44.87 60.36 79.64BUNG SAM PHAN 0.00 22.93 24.69 26.40 29.66 37.51 *46.09CHLANG MAI 1 58.80 47.00 33.91 36.85 43.54 65.58 90.71CHIANG MAI 2 58&80 47.00 33.91 36.85 43.54 65.58 90.71CHIANG MAI 3 54.56 47.42 50.90 54.57 62.51 85.73 113.47CHIANG MAI 3 (115 KV) 0.00 80.80 86.56 92.64 105.80 144.47 190.28CHIANG RAI 81.78 65.93 70.78 75.84 86.62 117.49 154.01CHIANG RAI (115 KV) 0.00 16.00 16.92 17.87 19.86 25.45 31.82CHOM THONG 23.40 27.21 29.26 31.29 35.47 45.94 56.60CHOM THONG (115 KV) 0.00 8.13 8.74 9.35 10.59 13.72 16.91KAMPHANGPHET 24.42 36.91 40.51 44.30 52.62 79.30 116.53LAMPANG 1 34.68 30.23 32.15 34.18 38.57 51.75 68.65LAMPANG2 25.30 29.05 30.89 32.84 37.05 49.72 65.96LAMPANG2 (115 KV) 0.00 40.00 40.00 40.00 80.00 80.00 80.00LAMPHUN I 13.66 21.29 23.80 26.40 31.83 46.84 62.69LAMPHUN 2 49.04 37.04 41.40 45.92 55.38 81.49 109.06LAMPHUN 2 (115 KV) 0.00 31.79 35.54 39.41 47.53 69.94 93.60LAN KRABU 7.31 12.91 14.38 15.89 19.01 27.52 38.04LOM SAK 15.72 15.05 15.99 16.95 18.96 24.64 31.61LOM SAI M1:5 V, 0.00 4.59 4.93 5.28 5.98 7.96 10.32MAE CHAN 0.00 23.02 24.72 26.49 3025 41.03 53.78MAE SOT 0.00 20.20 21.97 23.78 27.63 39.99 54.01MAE TAENG 0.00 0.00 34.40 37.20 42.60 55.70 68.82MANOROM 37.04 30.33 32.76 35.17 39.95 52.19 66.15MANOROM (l15 KV) 0.00 23.83 25.74 27.63 31.39 41.01 51.98NAKHON SAWAN 58.16 32.01 34.24 36.50 41.01 53.13 67.19NAKHON SAWAN (115 KV) 0.00 26.05 27.87 29.71 33.40 43.24 54.69NAN 25.42 21.43 23.13 24.94 28.91 41.31 58.26NAN (115 KV) 0.00 10.55 11.39 12.28 14.24 20.36 28.70PHAYAO 48.68 44.13 46.62 49.17 54.53 69.76 88.60PHETCHABUN 28.08 30.30 32.42 34.49 38.54 48.35 58.72PHICHIT 42.24 39.22 42.58 46.00 53.15 73.85 100.75PHITSANULOK I 53.84 47.00 50.35 53.85 61.34 83.31 111.01PHITSANULOK2 8.91 11.19 11.94 12.72 14.38 19.16 25.07PHITSANI)LOK2 (115 KV) 0.00 19.20 20.57 22.00 25.06 34.03 45.34PHRAE 37.24 33.58 36.11 38.70 43.96 58.69 75.38PHRAE (115 KV) 0.00 13.06 14.04 15.05 17.10 22.83 29.31SALOKBAT 17.72 30.45 33.07 35.66 40.84 54.67 71.52SAM NGAO (BHUMIBOL) 1.94 2.23 2.42 2.62 3.01 4.05 5.30SAWAN KHALOK 17.46 21.61 23.35 25.11 28.76 39.12 52.77SIRI}IlT 2.67 4.18 4.52 4.87 5.58 7.60 10.21SUKHO7TAJ 19.78 28.34 30.19 32.10 36.15 47.68 61.72TAK 1 31.43 21.88 23.80 25.77 29.93 42.24 58.51TAK 2 (PEA) 0.00 0.10 0.10 0.10 0.10 0.10 0.10TAKHLI 2 (PEA) 12.17 15.89 17.02 18.17 20.59 27.34 34.91THA TAKO 10.07 16.84 18.28 19.69 22.45 29.09 36.36THOEN 6.85 6.88 728 7.70 859 11.14 14.19THOENG 0.00 1825 19.46 20.72 23.37 30.96 40.08UITARADIT 30.72 42.34 44.95 47.68 53.51 70.83 93.07TAK 2 (PADAENG CO. MANI) 38.78 40.00 40.00 40.00 40.00 40.00 40.00TAKHLI I (CEMEN-I) 11.82 13.00 13.00 13.00 13.00 13.00 13.00OTHER (CONSTRUCTION PROJECI) 72.60 135.00 176.00 125.00 148.00 165.00 143.00

TOTAL 116L.09 1,477.37 1,61620 1.66604 1,940.71 2,561.75 3,259.20

-79-

I

APPENDIX 2

POWER FLOW DIAGRAMS

-81-

M~Od _A-, -4SV spa,t lung woi4Sa- Z ue4des 6ueg A4 oo5 pue 2 ueTdvS Buee Pu mw ooL x Z 41!M) t OOz Sddi MA Ppapod WesAssUuosssuwsuJl A)l 009X1 M[Od :11 3SF::) e~~~~~~~~~~~~~~~aJeJJJaisam a4a Ul sddi Pool )lead.o 10S6 dQd VSunr Peoi ";daq] buluueld UMBsAs _

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SYSTEM 2 00 1

*~~~~~~~~~~~~~~~~~~~~~~~~m NO &P;i i_7_3° Pi ;r 2 0o "I S.

it~~~~~~~~~~~~~~~~~~~~~3 - i.T:L7.S ~ ~ ~ ~ ~ ~ n z!): 1a

1-4 ~ ~ ~ ~ ~ ~ i0ii;t0; am;}5}i PAX

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; W | Systen Panning Dep71 ,L oa u9,P P5-1| Lgti a PsI h etrae | 4 -f | 5 0 0 K V Ra n 7 Is s S s e P r J c F o I P P s 1- 2 .0 0 1|(3h 2 7 0 M t B n S p a 2 a d 5 0 v a n S p a 2 C o u g 4 c t A E L - L 1m ~ . O" _A

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SYSTPM 2002

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_~~~~~~~~~~~~~A D ._.D i' .fS.1* ,xXijg.

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E tS !s i-d MX4~~~90Mwo

PEAK LOAD ^> X

| |System Planning Dept.,Load JunS4,PDP95-Gt Peak Load iIPPs In the westemarctta CASE LF - P02W|S|500KV Transmission System ProJect For IPPs 2002 | {Wlth 4 x 700 MW ait Bang Saphan 2 and 260 ksv Bang Sitphan 2 - Chom Bung 4 Cdsts.

.~~~~~~~~~~~~~~~~~~~~~~~~~~~T SYSTEM D200

r 3 trr

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.~~~~~~~~~~~~~~~~~~~~~~~~~~' .of

SYSTEM 2003

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2~~~~~~~~~~~~~~~~~

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LIGHT LOAD- ---

|System Planning DepL,Load .IunS4,PDPS6.O1 |Llgh2 Load |IPP5 In the westernarea (With 4x700+1,000MW at BangSaphan2

500f|ffOKV TransmIssIon System Project Fsr IPPs 2003 |and 500 kvBang Saphan 2- Chom Bung 4 cdt5.)} . CASE LF - LO3W

SYSTEM 2004

I 11 I j.. !'' e 1 ,-' S PI 1.12

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PE~~~~ARLOD.|9

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DM . - _. ... _

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LIGHT LOAD A717

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LIGHT LOAD A02

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*~~~~~~~~~~~~~~~~~~~~~~~~~~W NotC 4t

LIGHT LOAD <z

t | System Planning Dept. Load Jun 91, PDP #9- 01 |Llght Load iIPP h atr anea ( 6ih2x00kv a Rayog4-ong C;ho0kv 2 aon ccs -Wn o 2cbSOO 60KV Tr nsmlsalon System ProJedt For lP ~2IPPs .i00 th esrneandit 5xOxMWRatong4-NongCh oOkvyog-nNl 2 ccts . CASE LF - L01E

"" -.^.'5i1 /f:]}SYSTEM 2002

fff 9,ffi/ Sa i> oj, I

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| | SOOKV Thnsmistdon ~~~~~LSyse PntFr Ps|202 P and§0nRpn4NrCMx2ct.

-~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~ 0

SYSTEM 2002

igH rT ^'li,~~~~~~~~~~~~~~~~~- _ 11 42l

so. S.5 wLia.or

2~~~~~~

*P;;L ; a * . FD' *. fflT ue * *,1 oll tal tjols 25 0 _5POI 436~~~~~~~~~~~~~~~~~~~~~~~~=02 PAZ .0

- t: R-U- 02 -3.

i 9 ; m !i1' ., r f S 1 l l l l l~~~~~s 3a l . M

. ±1011 10 1 1.2 1 Z..oo 00:°s L

2Z.Z.0 0 .. 2500 JOM Rol _- _ _ _ _2- . ._2

is | yI Plannina DeptL,Load JunMPDPW95-O1 |ULght Load |IPP5 hn the eastern area (With 4x700 MW at Rayong4; BOOkvRayong4-WangNol 2 ccts.|

* System ~ ~~~~NDAD MCAS E FL2

| 600KV Tranamiuslofi System Project For IPPs | 2002 and 6001w Rayong 4- Nong Chokt 2 cdts. )IAELF-L2

*w .N- M

Ansmi rs sys'rEM 2003

- >°}°r5 / X / L 23~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~r. ~ ~ ~ " A //2r Q)Q2

il -r;1t'S1 -- fl1 ;~~~~~~~~~~~~~~~~~~~~~~~~~

I w ! a: ,,,,, s .. ..................IM 1 1.1.L sea" R I Ir 1t

~~~~~~~~~~~~T= I II 1>02. 1 1 } };° } } } ° f f i X Dle | I_~~~~~1.41

P E A K L O Ar *e23 | L t l ) i _ _ _ - 2 |--- ---- ---E _ _ . _._. . 1 - | __ _ _ | I~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~i| 3 Sytem bnnn61 ept,Loa Ju94,DP9501 Pea Lod | m i th eatrnare ------------- Wa Ryng; 0kvayn4-anlio| tr| 60 K Trnsmssin Sste PrJectForIPP | 003 j 2cds an 50 kvayon4-NngCox css >| CSE F -P03

SYSTEM 2003

Z | A[i t 3

SAT N00 I . or

2~~c 2

_ System Planning Dept., Load Jun 94, PDP 95.-01 Light Load IPPs in the eastern ar ea ( With 4 x 700 + 1 ,000 MW at Rayong 4; 500 xv Rayong 4 -Wang Nol CAS E LF - LO3E500 KV Transmission System Project For IPPs 2003 12 ccts. and 500 kv Rayong 4 Nong Chok 2 ccts. )_

3 ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~~ _ __._

![,', ,m ~~~~~~~~~~sys'rEM 2004

l 1 3w>3X5 8 3 L S. - M

M t n 9 : ti+_L I I bs p..L I~~~~S1§1 a,2 t -Wjeelll~~~~~~~~~~.0

0< l2 1 i ^. of _ _ fr : tjl°z 1| *. ~~~~~~~~~~~~~~WAG I P^

NF f | tf li, . ;P-lsJ Lj6 l l l l l~~~~~~~~~~~~~~~~~

1-AIZ; w | | 2°J n l

I.-~~~~~~~ mmtt4}o�t r_ r

PEAK LOAE ^,0 l RÔNC 3x,A| t |Systm Plnninl Det., oad un 9, PD 9S 01 Pea Loa | IPs i theeader are ( Wth 4x 70 + 2x 1 OOt viW t Raong ; S0 kv ayon 4.-WangNoi2

| | ~~~~~~~~~~SOOK TrnmslnSse rjc o Ps|20 cs n OkRyn4Nonghk2ctr |CS F-P4

g1"0' -' ^,, SYSTEM 2004

2 I T t~~~~~~~~~~~~~~~~~~0 400 IJQ

. -1Z//7 a gzaW i1°4° 1 -a C-,,

L eI GHT LOAD 11

t : A t~~~~~~1, 1111w I I .2Z 11- m $ ttJiSM 1 2 1

~~~O0~~~ KV Transmi-s-on SytmPojc IPP I 200 "1' It

14 4 l LL:|t4U3~ ~ ~ 9ii1}X}1t}10 t '___jtO

LIHTLOD 8D [ F:Ql WS3D

. ~ ~ ~ ~ ~ ~ ~ ~ ~ ~~I -7 - - --- U

I'm~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~ RA ACII y5e lann Dp.LodJnS,D95O LgtLod|PP nth atenra Wt 4T02x,0MWMRyog;WkRyng-agNl

| gJ | 60 KV TransIslnSdmPoetFrIP 204 |2csan5WkRaog4-NnChk2c. CA LF-0E

J.,

ATI ~~~~~~~~~~~~~-M 4t SASY S rEM 2 00 5

01.0. -O i /.0 2'F

= , W~~~AM NO] w 7

1 - X /// ' t$SgS ~~~~~~~~~~~~~~ 2 13 f

S i f >/ ' W _ W ~ fiS g __ '.1, 22;"A : :,S Ols7 . L .>gRH HF:11- 'WC t e... ,. I~~~~~~~!M>; 44;m: ; F ;~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~

S5 f_AT NO I t° m r rw04 StA

1

PrSl -Sff"=4 10IM~~~~~~~~~~~~~~~~~~~~~~}135>q6>t)111111}1}Isls

BAMXOK~~:ml°°7}°l°1}° MI1 -,'PEAiC LOAD 8°:! S22m | .4~~~~~~~~~~~~~~~~~~IDi

Ml.ft 1-~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~C

| yse Pan i g e t. L a J n 4 P PSS- t| e k oa I P5 i t e eatenara it x70 4x1,00Mka R y ng4* 00k R yo g4 an iii | t | OOK Trnsmssin Sste Prjec Fo IPs | 200 | ccs. nd OOk Rayng4 Non Cho 2 ds. | ASE LF Po E

. Arz 4 T , ,,/ SYSTEM 2005

51, 2~~~~~~

u ML ~~~4L3 -, -

SAI NO! to -

4,

LIH Li' OAD

| 3 | ystemPianning Det,La Jun 94, PDP gr_01 |Light Load |I75in the easterna~rea (With 4 x700.4x1,W000vMW at Rayong 4;500kvRfayong 4-Wang Noi| CASE L.F- L05E | { f15W KV Transmission System Project For IPPs | 2005 | 2 ccts. and 500 kv Rayong 4- Nong Chok 2 ccts i

Ln~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~

At2sB0t 4tnm mx ~~~~~~SYSTEM 2 00 6

j r = :~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~1' !//S wl zZ$ot 2 1 oss _ ^ WA9G 1

[~~~~~~~~~1 V :; "__i.; _ 0 ,1

-'r ,, SX,,, l6- t1I i;8 ~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~cE xE s__s

L; ''2j;|; ^ ............... < !- I ....................... r jlj ii44=24-t|3 2

g~~~~~~~~~~~~~~A MI-l 1:z. _ _. i miLua7ox ero -12

g F s O tj t t X,015 ";g L.x- l r ' 177 27 rw i o t

,, A m = = 4 d | i | I ! ] ! X j4;;

C)~~~~~~~~~~~~~~~~~oXt IIa''''}rnggzosoWsW0w0- ,e3°,¢

PEAEt~~~~~~~~~~ LOA -21,,,|7 TAOQig222 g~~~~~~I .7-ytmPann et,odJn4PPf-1|Pa La Psi h atrae Wt x0+x,0iW tRyn4S0vaoG-agoICS F-P6

g t g 00' Tanmisio SytemPrJec Fr IPs| 206 2cds ad SOk taong NngCok2 cS.4 _ t~~~~~~~~~~~~;

IIA71r7l~ S..ll SYSTEM 2 00 6

4 -=),== t:'1' g~~~~~~~~~012/}2<// so661 t@t*~~~~~~WANG 2N;4 _

<ES T2i'-sal:Ceos f11 t~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~

; .0 NON @; ' i T 15 rDO _; g v s i

! ^ a1;. 1 r aB: _ _ : f ; J 7-t 61 :~~~~~~3

Ar : > _O5 8+ f

8 z x t i . ;2j) j) |+t F q; oP7 ' ot _W I 5| * 7 NL 2 t;,

s t $S0+ XsIF lini V~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~

< ~ ~~~P 4 1 0j- r...................................'""' ' 4 2Fi''.........Il;4_ _i SllliBAK:ol7 i A PW |;I rT

m":1 Fi' a Lu 1[1 , Im~ ~~ I' 0Jt-S$IIII S zts 7ti

NORTH~~~ ~ ~ iiiWs-; ;;};S 3 . .

LIGHT LOAD ,,, 1 7UtYONC t222gg' |SOTH |A t J O PH&

> | Systm Plannng Dept ,Load un94,PD95-01 |i ight Lad | jP5 in th easterarea (Wth 4x20+6x 1,00MW at Ryong4, 00xvRayng4-WanNol| CAE LF- -L06E IF

| 15 00K V r anm isi o 5ytemProectForIPs |200 | ce. nd 00 v Ryon 4 on Chk 2cct. -1 5

5tt lA 2 4 7 ~~~~~~~~SYSTEM 2 00 6

ut 3 v zo2 // 177it ;1!1Wm m

r A NOr J -0X i 7 X

I ,4mi ~~~~~~~~~~...W3... S11......1

| m 7 >l T S Z l<D |~BAKM m

| PEAK~~~~11 LOA l! A7||..........: o.O

.~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~i _ _,

I ZJ | Systm Planning Det,La Ju3,D3-01 | ekLa lPSiSh atenra{h4x7061WM at PHUg,01tRyn4WagN A

| Xy | OOKV Tansmisson Sysem Projd For PPs | 206 1 _2 ccts and SOkvRayog4-Nonghok 2ASEs.LF E -LF 0-P06E-2

SYSTEM 2006

tW 2 ~~~~4 g _ ta¢Xooofe I~~~4 I

:11~~~~~~~~~~~~~~~~~~~~~ ~ -l - -!a - - - - - -- - - - - - -- - ' 5 ¢ 8 -i

PEAK LOAD . o, RAY iN1 zJ r go

.~~~~~~~~~~~~~o RA= . Y

kv' System Planning Dept.,* Load Jun 94, PDP gS-01 |Peak Load |IPPs in the eastern area ( With 4 1:700 . 6 x 1,000 MW at Rayong 4; SO00kv Rayong 4 -Wang Noi|CSdF-P6 \t 5 00 KV TransmIssion System Project For IPPs | 2008 | 2 ccts. and SOO0kv Rayong 4 - Nong Chok 2 ccts.) CAS LF . OE

it.~ IJ

SYSTEM 2006

S.. is.Y 0 05 , 0 7

< ; -8 1 att 2 iIjos '' 1289~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~1

s~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~ o

\~~~~~~~J~-C 600 KV-g Trnsisio Syte Prjcno PsI 20 c3 n 50k aog4-Nn hk2c

PEZ\R LOAD 1, l;.J"' u t- oom

_ ~~~~~In . 4 .. AD P,

t yte bnigDpt,LadJn94 D 9 1 ek od| P n h asenara(Wth4x70 x100 Wa Ryn 4 0 ivRyogZ- ag °|cs2L P6 ,,,9 | 500 KY Transmsr,;ion System Projet For IPPs | 2006 12 css n 0 v aog9 Nn Co cs

SYSTEM 2006

1''~~~~~~~~~~2

, l t' ' t f t 0 H M i~~~~~I, -

i "1 -S 91 & '42f1+ ;FF 11 11 t~~~n - -

SAI NW = i.< $ Il

LIGHT LOAD ,|,!K 3t| 't

| y|500KV Transmission System Project For IPPs | 2006 IP| i h 2 ccts. and 500 kvR~ayong 4- Nong Chok 2 ccts.1 l-

System lannin Dept.,oad Ju94,P0P9-01 Liht Loa (With x700.61OOOMW t Rayog4.; CAE LF -LO6E 2

590M TSA S7 SYSTEM 2006

IT1.~~~~~~~~~~~~~~--1.0

t :~~~~~~~~~~~~~~~~~~~~~~~~~~~~~1 .. 5 , ,

l _0 ,IF..7

--- 1g ,,j -- I _----- T. -1" l 2i

-LIGHT LOADflx.1

SystemSO Pvlannmil5eng Pt. Ltoad Jun 94, PDP 95-01 |Light Load | PPa in the eastern area ( With 4 x 7 0+ 6x 1,000 MW at Rayong4; 500 kv Rayon g 4Wang,Noil CASE LF - L06 E -~

\~j~ 500K Transml~ion Syste Project or IPPs 206 2 ccts and 500 v Rayong -Nong Cho 2AMcUK.

SYSTEM 2006

59. MM NOI~~~~~~~~~~N~O N50~N.~

LIGHT LOAD-------------- //- -- = - - -

3 12f : A X _ _________ __ _ _______I

System~~~~~~~~~~~~~~~W PlnigD..La u 4 D 50 ih odWt x0. ,0 PAW at .aog4 00vR n 4 Wang CAS tF - L E -4 1

500KV TransmissionSyte I e Fr _ in t 2ct anh s o

1 l|2>g)a,- H t *" is l<X Lj iuz

> < <0t~2

r

S" ~ ~ ~ ~ ~ ~ ~ ~ ,11 PHR111 i"f _ '° 1 .: >

LIGHT LOADCN|l,!5s;i w m ,

| f¢b1system Planning Dept., Load Jun 94, PDP 95 - n1 Light Load I PPs in the eastern area With 4 x 700 + 6 x 1,000 lItW at Rayong 4,; 500 kv Rayong 4 - Wang Noi| CASE LF: L06E -4||0 | OKV Transmission System Project For IPPs | T 20th 2 ccts. and 500 kv Rayong 4 -Nong Chok 2 ccts. )

SYSTEM 2006

bm Mr

PEAK LOAD ; 5

l\ |System Pbanning Dept. ,Load Jun 94,PDP 95-01 | Peak Load |PPS in the eastern area (With 4 x700.6 x1,000 MW at Rayong 4; 50kv Rayong t- Wang Noi|cs FP6| f|500 KV Transmilssion System Project For IPPs | 2006 |2 ccts. and 500 Kcv Rayvong 4- Nong Chok 2 ccts.) CAS FlP6

>5 ;2j ls / 4nj 4§,Otr 5;: , Xl ' Ft -.RSYSTEM 2 00 6

.ic.io.isoo.E _ //S i7' X L u:, cO

L~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~Z- SAXj 4ArUs

1:'?,,~~~~~~~~~~~~~~~~~~~~~~~~~~~~~l NM CR-,X OK,1 1i 1::i:--" " 11 li3

_4 _ _ _ _ _ :j'

I .. H WE~~~LIGHT LOAD 1ai3 51

X~~~~*.:,~~~~~~~~~~~& ,., ,NC1W ~ ~ ~ ~ ~ ~ .

} System Pbnning Dept.,Load Run94,DP950 1 ih o d IP nteesenra( K x0+x,00 W a aog;0k Ryn4W n Nlc F L 6M0 V rnm isb Sytm4oe o IF. 0 62ct.adS0k ayn4-Nn hk2ct

SYSTEM 2007

PEAK LOAD !:55:5 I55 NC,

System Planning Dept., Load Jun 34, POP 9S - OR Peak Load IPPs in the eastern area ( With 4 x 700.*8 x 1,000 MW at Rayong 4, 500 kv Rayong 4 -Wanig No AElF- OE \v, 500 KV Transn¶lsslon System Project for IPPs 2007 2 ccts. and 500 kv Rayong 4 - Nong Chok 2 ccts.)ICS F-P7

_J~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~

SYSTEM 2007

/ / / / .@ _ 1f)tOtW ) r | s q~~~~~* ~ ,. ..2~~~~~~~~~~~~~~~~~~~~~~~~~~

EF,,,, g ~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~-- -i-t

3 + S e=77i S=S 2

.,I .. , II11 : X[1

. System Planning Dept., Load JuJn94 PDP 95-01 Peak Load IPPs In the eastern area (Wlth Asx700 + Txt,000 MW at Rayoig 4 500sv Rayong 4-Wang NoifCS FP7 jj ¼i/ 500 KV Transmission System Proje.ct For IPPs 2007 (2 ccts. and 500 kv Rayong 4- I Nong Chok 2 ccts.) CAEL -P7

.. . . _ _ _ _ _ _ _ _ _ _14

APPENDIX 3

DYNAMIC STABILITY CURVES

-119-

!~~~~~~~~~~~~~~~~~~~~~~

In 0n3SYSTEM PLANNING DEPT. PDP95 PEAK 2001 SYSTEr PLANNING DEPT. PDP95 ,PEA 2001fJd 1 A IPP AT THE WESTERN AREA (1400 MWI3 PHASE FAULT AT BSP2 ON 500KV BSP2-CBG LINE ° 3 0PHAS FAULTL 4 CSOCi] PEN FAULT LINE 4 CYCLES OE AL IE4CCE

C's YFILE: P01W F i FILE: P01W uc- > L _CHNL1 20: lANGSNfR H551 1 CINL 41: (V:230KV RY2I 1

0 D C - - - - -50.0 | 1. 3000 0.30000CONL IS (14 AG EPK Tll I'CONLI 36: (¶1:230KV ORTI r-150. 00 . -150.0 ~" 1.300D0

150 00 C 0 13 IANG MH3 T31 -150 0 i 1 3000 CHNB 34 IV T3031V 0KV NB1_3[150.00 ~~~~~~~~~~~ ~~~~~~~ ~ ~~~~~-150.0 I 1.3000 * C130L8 2h-00 CHNLI 10: IANG: KN G111 - 150.0 | 1.13000 CHNL4 2il: lV SOOSV 81131 v 0 30Q0 |

CHNL0 1: IANG SB T1 ] CHNL0 32: IV:5000V CBGI _E150.00 - - -150.0 I (1.3000 0.3oO00 I

150 00C -150 0 | 11 3000 CIL0 31 IY 520KV

10 t0 :0

o C~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~' 1

: E~~~~~~~~~~~~~~~~~~~~~~E

a.o N

(A(-

41 ,k~~~~~~~~~~~~~~~~t

I 9.... ~~~~~~~~~~~~~~~~~~~~~~~~~~~~fO :

A.,~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~U

()

SYSTEM PLANNING DEPT. PDP95 PEAK 2001 SYSTEM PLANNING DEPT. PDP95 ,PEAK 2001IPP AT THE WESTERN AREA (1400 MW) IPP AT THE WESTERN AREA (1400 NW) r4LINE TO GROUND FAULT AT BSP2 ON 500KV BSP2-CBG 2 LINES * LINE TO GROUND FAULT AT BSP2 ON 500KV BSP2-CBG 2 LINES

O ,FIII OPEN FAULT LINE 4 AND 6 CYCLES (CONTIGENCY N-2) OPEN FAULT LINE 4 AND 6 CYCLES (CONTIGENCY N-2)Cd ~~~~~~~FILE: P01WBSP2-CBG FILE: POIWBSP2-CBG ath

D.. | lSo.oo CML 20: [ANG:SNR HSI .- A: -150.0 | | 1.3000 eaLe tl :230KV RY21 -, _ _ - 0 1

150.00~ ~~~~~~~~~~~~~~~~~~~~~~~~-5. 1 C4 11.3000 1

150.00 CH 13 I AG:B PX Tl - - - -lS0. 11.00 0 c t 36 Iv 230KV SRT - - - 0.30000

CM#NL 10: [ANG BK GIllj CMM#L 20 [V:2300V SRT1

150.00 -- - - - 150.0 N | 1 .3000 c. . . 0.30000

I150.00 CLOS - - -150.0 1 il.3000 32-0.300001 150 00 ~~~~~~CHNL# 10: [XNG XN GllI - - - - - - - _, ---- 150.0 i 1. 3000 CHNBt 283 IV 00XV HH3E 100

|150-00 CHNLt 1: rANG:SB T51 . loo1[00CHNL# 32- MV500XV CSGI _ _. 030000

I ~~~~~~~~~~CENLI 25: rAN4G:WIP Ul] CKN,, 31: [V50011V ESP21

| 150.00 CN -150.0 | 1.3000 3- 31 0.30000

~~~~~~~~~~~~I I 1 '" °I Ill1111 o

0 I ; f 0' lD 11 If t1)~~~~~~CoI 0

I~~~~~~~ ~~~~~~~~~ I -ftc jW

0 ~~~~~~~~~~~~~~~~~~~~~~~~~~~~~0

S CIit~~~~~~~~~~~~~~~~~~~i

I H ~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~04

oO~~~~~~~~~~~~~~~~~~~~~~~~L1 :0 it .u~~~~~~~~~~~~~~~~~~~~~~~~~~~~~U

f,ZI1 SYSTEl PLANNING DEPT. PDP95 ,PEA 2001 SYSTE( PLANNING DEPT. PDP9 PEAK 2001 te ) pw-e SIPP AT THE WESTERN AREA (1400 NW n)- IPP AT THE WESTENU AREA (1400 NW) in LINE TO GROUND FAULT AT CBG ON 500KV CBG-SNO 2 LINES ' LINE TO GROUND FAULT AT CBG ON 500KV CBG-SNO 2 LINES .

O) t Ej OPEN FAULT LIKE 4 AND 6 CYCLES ICONTIGENCY N-2) - D = OPEN FA13LT LINE 4 AND 6 CYCLES |CONTIGENCY N-2) Oi;FILE: P0WNCBGS_O _0 FILE: P01WCBG-SNO _ O

*~~~1s~~. I 15000 LA~C&$ :NDi US IL...... 100CENL 41: lV:2301V RY2 -- ) 0300

-lic 1150.00 ------- -150.0 0. 3: V20I 10

150.oo CHtiLl 15. .:P Ti~x-JA -ml-m- -K 150.0 J 13000 1M 6: tV:230HV SRTI ] .00

-150.00 - IL-3.-1_-- -150.0 ; 1.3000 CM# 34: M2300 NBI 0.30000 | |

CO50., 10: 1M6:uN Glill ._ ._ v . CR.00L 28: IV:500H V O 131 .N | ]

|1 5 0 .0 0 - _-1 10 0 0 - -1 : 1 1 3 T51 . - ...1. I [ f 0 32: I V :5 0 0 V t - - 0 .3 0 0 0 0 j a

C H N ;1 2 5 : ! M W : VI P 01 11 - e C- .#* 3 1 : IV :5 0 0 1V 3 s P 2 1 e C I

I .~~~~~~~~~~~~~~~~~~~~~~4

IJ i i

_ Cr'''',''/\ tR _ 0°,~~- _ l, tY,' fip_O

(~~~~~~ '1s ' 6'i5\ \H

I I 1 1\ ~ ~~'.w t t I I ° I_( - . .. . . .4{

.~~~~~~ .. .-

* I 4( I~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~

0~~~~~ 0

r iSYSTE2( PLANNING DEPT. PDP95 .PEAK( 2001 j~ ( 1SYSTi PLANNIN DEPT. PDP95 SPEAK 2001 rVW1IPP AT TOiE WESTERN AREA (1400 NW) U W~'1IPP AT THE WESTERN AME (140 NW) I

|-1 LINE TO GROUND FAULT AT CBG ON 500KV CBG-WNO 2 LINES |LINE TO GRON ALT AT CBG ON 500KV CBG-WO 2 LnIESOPEN FAULT LnIE 4 AND 6 CYCLES (CONTIGERCY N-2) OPf FAULT LIN 4 AD 6 CYCLES (CO1TIGDNY N-2) in

FILE: P01WCEG-WUO FOM,01~GlUOja 150.00 F-. - - - - -1500 1 1-3000 0: POli- 10_ _ _ 0.30000

150.00 CML 15- rANG:BPK Till xj...... -- 1-so t 1 .3000 r 35s IV:23V fl ------- K 0.30000 |

llso.oo ~ ~ ~~~~mufr. ra1, sa _A'p TS)o c;1-00rw03tons 3sM0K IPPI --- + e3oe1l150.00 N ol * -- -Vsu.e F1K.3000 ---rv- 0.30000 | ;

| 150.00 ' C0rII 10: 00: SB GiT5 -------- = -15.e0 11.3000 C4NL 2 : yj 1 0.30000 I -II0 1 11.3000 ~0.300000

cmiii 15 10001-sD '15 - I CMIi.. 16 Iv:som wo.0.0a0

|150.00 em5o.es0025: till - I cir..oi lv 5eK300021

_~~~~ ~ . * _t:i.1@_e:0

S* I I.~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~

I 0~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~0oI I~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~W

j. ~ ~ ~ ~ ~ ~

x r SYSTEK PLAOING DEPT. PDP95 LIGHT 2001 SYSTE4 PLANNING DEPT. PDP95 LIGEHT 2001 Tl n U\ FP AT THE WESTERN AREA (1400 KW) IPP AT THE WESTERN AREM (1400 MW) aO

3 PHASE FAULT AT BSP2 ON 500KV BSP2-CBG LINE 3 OPHE FAULT ATBSP2 ON 500KV BSP2-CBG LINE011EN FAULT LINE 4 CYCLES O52CG IE3PHEN FAULT ATN BSP 0CYC0LESP2C LNCd st 2150.00FILE; LOIW FI LOi|

CUM#, 20: rAi#3SNI H51 @ cOL41I:2301KV 1Y21150. 00 C 11.3000 - 0.30-e - -

so-oo CEL#15 f^S:3Ta31____- 113000 [ BT.f36 IV:230OVR _ -T 0.30000

150.00 o ........ -150.0 E1.3000 .2tl: lv 5o.X.. 0.3009j AI~150.00 ----- 1001 00----- .00

II50.00 CU# 10: tANG:SB SSI1 - - -- -10. - - -13e CM# @26: IV:SOOI:Vt I _ _ 0.30000 |1 350.00~~~~~~~~~~~~~~~~~~~~~~~-5.1360---

so0.ooc* 5:I0l -150.0 V p 1.3000 elo 1rsonsP * 0.3000e

dune 25. U ll 1 1 . 3 0 0 0~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~0300

_ § t y 4 & I I . | ||Egg

0 j~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~IC

.l 1l

SYSTER PLANNING DEPT PDP95 LIGHT 2001 *- SYSTEM PLANtING DEPT. PDP95 .LIGHT 2001 *1[ II PAIHEwsER]m (10 W IPP AT THE WESTERN AREA (1400 NW)l~ ~~~P AT THE WETR A OE r10 , NP

TIEWSEW RA(40D50 G2IZ

LINE TO GROUND FAUJLT AT BSP2 ON 500KV BSP2-CBG 2 LINES LINE TO GROuN FAULT AT BSP2 ON 500KV BSP2-CBG 2 LINES ). G L'" I OPEN FAULT LINE 4 AND 6 CYCLES (CONTIGENCY N-2) mOWl FAULT LIE 4 AND 6 CYCLES (COd IGENY N-2) I

FILE: LO1WBSP2-CBG FIE:LlWS2-B

S150.00 CDOL0 20: IANG:SR H51 _ , -1 1.3000 aIo *1: [V:230XVKY2I >, _ -_ 0.30000 | g

CEL# 15: ROD IPX Tit I 4 CM#L 36, V21OKV SRTI .....150.00 0 ... 1 1 . . . -150.0 | N |.10000 I

cHN., 13w fOAD 221 TR]~ CElLO 34, FV1-230KV EB) 0. 80150.00 - - ---- -150.0 |11.3000 ----- ' e.30eoo I g

|150.00 CM#L0 10: tINGAN - - - - - -10- [R- -150.0 |1.3000 CHNB5 2i: tV:5oxvMI ---------- 0.30000, |

|150.00 . -150.0 | | 1.3000 CID-IL. 3 0.30000 |

b 50.00 CHNBO I5 ram :II-P- -~lS 0 1 | |1.3000 CElLO 32: OV:5001V BSP21 - 0.30000 | CElLO 25: tAO: NIP il 'CElL 31: 01:500KV .SPl1 0

,50. 0--150 0 11.3000 .- r:000

I .

>

ro ...

*10~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~,

- I,~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~7

I . 0H [I~~~~~~~~~~~~~~~~~~~~~~~~~~~~~U

_ _~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~c

SYSTEM PLANNING DEST. P9 L PLANNING DEPT. PDP95 ,LIGHT 2001~~U r- IPP AT THE WESTERN AREA (1400 NW)1?ATHEWSRNRA 1014)ItLINE TO GROUND FAULT AT CBG ON 500KV C3G-SNO 2 LINES INP AT TON W AUTE AT 140 N 5 2LEk)iV i O1?EN FAULT LINE 4 AND 6 CYCLES (CON!3TIGEN'3CY N-2) OPEN FAULT LINE 4 AND 6 CYCLES (CONTIGENCYCY N-2) IFILE: L0lWCBG-SNO FILE: LOIKWBG-SNO *fi 3

2 X { ISO OO ~~~~~~~CHNL 10, IAHG_5R SI _ E -1501 130 CJDW e3, IV 230XV B2103001 |150.00 cw§1 aG5sT1^|13O §3 V20WIXK0.300001CN#15: [AM:G PK TIl . .. -5. I 1. 3000 CHNLI 36: [V.230KV SRTI . " 0130000

I50.30 CHNL 13 U 3 3 11.3000 _ I T CHlL. 34. IV 230KV NBI _ _ I 0150.00 -1506 0 1 1 1.2 .30000 1 :

1 150.00 ~~~~~CHNL0 10: [ANG:KN Gllll0. 1130 CHNL 2a: [Y:500SV M310-001

i150.00 CHRI 1: FANG: S T51 -150.0 1.3000 CHL0d 32: IV:500KV CBG1 , 0.30000 |

|150.00 cH-o -5: tAMAGPUll 150.0 1 1l.3000 CM- o31 [VSOOKV85nl 0.30000 I. I I I '11 1- 1 I V I , I >oI I | 1' ' ' I ' ' o

I 0 a~~~~~~~~~~~~~~~~~~~

_ , *, a | ' _ o _ t I ' O _ o,I I 0 ... l

. .

. _-_ _ . _

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FILE: P02WBSP2-CBG FILE: P02WBSP2-CBGCENBL 20: IXAG:SNR H51 0| CHML 41: fV:2309V RY21150.00 - - - - - - - -150.0 I 11.3000 - --- - - --- 0.30000CMiNI. 15S [AM: PK Tl I CaM.. 36: 11V:230KV aRTI

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FILE: POSW-58 FILE: P05W-58 i

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4 co ~~SYDETSTEK PLANNIING DET DP95 LIGHr 2005 In SYSTEN PLANNING DEPT. PDP95 LIGHTP 2005IJZ1IPP AT THE WESTERMAREA (5800 MW) (SPLIT BUS AT SNlO) tW- IPP AT THIEWESTERNAREA (5800MNW) (SPLIT BUS AT SNO)LINE TO GROUND FAULT AT CBG ON 500KV ICOS1FIGENCY N1-2) LN OGOi AL TCGO 0X CNIEYN2

I ti ~OPEN FAULT LINlE 4 AND 6 CYCLES (CBG-SSIO CBG-SN02) u.P. TAULTOUNKEFAULTDAT CYCLS CBGNN 50K (CBNG-SN0K2)I 4 FILE: LO50CBG-SN02 Fl IL: LO5MCEG-SNO2 L

~~ j cuE., 2p~~~~~ Ohm-ouR 055 - - - -~~~~~~~~~ -150.0 1.30001 ~~ E#lISO 15 Om.aiW TIO 150.0 16, flt-230111 9= I

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I-

SIN=L LINE To GROUND FAUlLT AT RY4 ON 500KV RY4-WH0 2 LINES SINMLE LINE TO GROUND FAMTL AT RY4 ON SOOKV RY4-WN0 2 LINESOPEN FAULT LINE 4 AND 6 CYCLES (COZITIGEPKY N-2) 0OPEN FEIlLT LINES 4 AND 6 CYCLES (CONTIGERC N-2)

FILE: PO1E2RY4-l00 i LE: 1nV000 X

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FILE: L1E In2OEN FAM 50 1 CCLES ICD.: PLE L EFILE: L01l at1PO'L d 150.0 - -- - - -1500 1.300 CL0 30: NV:50KV PI0.00o

0M0HR R)0 0 141 AM: llCMM# 30& tV 230KV ST 15.0 -- ..... u -150.0 il1.3000 x - * 0.360000 I Ccm.. 10, lm52-R Tel CUILO 23: WM=00K NO

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150.00 - - - - - - ~~- - - -150.0 i 1.3000 -- - - - 0.3010001CMM# 20 1A052 GIP 1)ICMML 21: 111500KV NMI)kso.ao~~~~~~~ -150.0 il1.3000 e- - - 0.30000

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FILE: LOIEl FILE: LO1lEltC1.ILI 16. [AM-MM NS1 at - I MPBP 3 _ _ #,I

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1150.00 c-150. C's 11.3000

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CMM# 16 [A02M, SNR aa ' VI CEI.* 27 rif:5001V n3PIP| 150.00 16: - - ' -150.0 I 11.3000 s- - - - - - .30000 | 0

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| 150 oo 0o 13' ISO.I.X3 TVI _ 1 3000 L. . .I.v 3 ) . . 0.30000 | g

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150.00 - --- - - - - -5. 11.3000 - - -- - 0 - e.30000

so0.oo CM# 20: r NG0ErP 0ll 0 (I s - -. 3000 CuSis 26: Mv:5001v rY41 0.30000

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ta .J:7-" OPEI FAULT LINES 4 AND 6 CYCLES (COkTIGECY N-2) I OPE FAMLT LIE 4 AND 6 CYCLES ICCOTIGENCY N-2)FILE: LO0E2RY4-iNNO FILE: LOlE2RY4-WO ,O

| lSO OO ~~~~~~CHNLO 16: *:llfSI, -lSOO|R 1.00017 DfV:SO: 9BPPI w ,__ .000|- 150.00 a - - -- - - -150.0 | | 1.3000 1- -- 3x 0.30000 >

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< A | 150.oo - CHNLC 16* ct L 27: V:SO0KV EOS oP _|

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it ~ P4FUTLNE N YLS(COIE0Y1-)OPEN FAULT LINES 4 AMD 6 CYCLES (COTEfIGENCY 11-2)a |150.00 FILE: PO2E2RY4-o-| FILE: P0292RY4-WNO

I50 otCNN 16: rA3N:lSNR O | a |all 20: )51-D-v -RE-x 0.30000 |

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150. 0 O30,00 16: IAC: 651 - - 0 27: I - 0.30000 | > O1at 14: I): ,,PK T-| 1.3 00 CI 30: IYV2301Y M.a30000 |

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V.) 4) FILE: P07SE an FILE: PO7SE

i>. i | 150.00 ~~~~~~CMNL 16: IAS)M:Sl H5L >. _.- ----lS. DM R | 03C 3Iv:soxv RBpPPi ___ o300| C | 150 00 C 1 -150.0 1.3000 -L : Iv:20xv 5- - - - - 0.30000 |

|L. 150.00 CHNWL 14: iANG:B5 00K Tl CH1.3 300 iV:230KV SETI N 0.30000

150.00 CHa0 13 0r W TE CR1&4 23: [v:230KV 0N1 o N0.30000 |

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| lSO.0OO CHNBI 13 70082.N3 TBi j _ _M# _10 _0 IV:230KV NBT1 _ _150SO.00 CHNLO lO: -ANG:DI -lil -_ _ _ _ _ _ ., -150.01 C o 11.3000 0 23: {V:5006v 1 _ _ _- - - -- -- 0.30000 I

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APPENDIX 4

FAULT FLOW DIAGRAMS

-205-

I

SYSTEM 2005

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* , -5.3 A E MM00 OCH1 AIK

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~~~~~Im

| |System Planning Dept. ,Load Jun 94, PDP 95 -01 |3 -Phase F:aultl IPPs in the western area SookvB4ang70 ap3 xt ,000MWa Bung Saha 2,ts CAS SC 05-1 f|500KV Transml5slon System PtoJect Fo, IPPs | 2005 an SWkvBangSahn-hr buns at Sats |NASS-P0W-

5t 4§rim m ~ ~~~~~~~~~SYSTEM 2 00 5

71~ ~ 77s@ _37 S _ J.

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SYSTEM 2006

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| | Syistem Planning Dept., Load Jun54, POP 95-01 13- PHwASE FAULT | IPP5 in the eastem are;r 1(Wfh 4 xroo t xItooo Mw at Rayong4; sookv Rayong4-Wang Noi| CASE SC P06E I \~ 50 SOKV Transmission System Project For IPPs | 2006 I 2 ccts. and 500 kv Rayong 4 -Nong Chok 2 CdtS. )

SYSTEM 2005

S y te P a n in e pt |. J u ni 34 P O P, 9 5-0 1^. 1 -a P. 1 k IIHA S F A L T -I= P

C ~ ~ ~ K Ta s m si n S te Pro ec For 3i P_ _ __s1 20 0 L 2 c . and 600 kv R y n -N on C ho 2 C s.

T~~~~~~~~~~~~~~~~~~~~M .E@ lX2

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a2

APPENDIX 5

FULL NAME AND ABBREVIATION OF SUBSTATION

2

- 211-

a I

Appendix 5Page 1

FULL NAME AND ABBREVIATION OF SUBSTATION

40. SUBSTATIONS ABBR. NO, SUBSTATIONS ABBR. iNO. SUBSTATIONS ABBR.

I. AMNAT CHARDEN AN I85. ILAM POO R(A L R 1169. IPHUKET (42 P1(162. ANG tHomG f&2 ATl&2 86. LAMl rAK(HoMG _ l TO HMPI

3. AO PHAI 14 1.LTPAG(2 tPI&2 171. P0M,G BON ________

4. AO UJDOM -- iAU 88. LAMTPUHU 62 114162 (12. PR)A-H(N DURl I62 PAI&25. ARANYAPRATHET AR 89. LAkM KRABU LK__ (( 173. PRACHUAP KHIAI K(HAN PK(66. AUTTHAVA 142 AYI&2 .90. LAY PHRAAO I-- PR (r4. PRAKTHON CHAIPK

7. DAtI4ET MARONG DM14~~~ON 91. LANG SUA LSN (175. PRAMH IURl PRO6. DAN BDUNG 05o 92. LI I.I (r6. PRAN DURl POWER STATION Pli?P9. BAN COK CHANG BCC 193. ILOEI LE (r7. RAJJAPRADHA (CHIEW LARN) R(PD(0. DAN DON ODN 194. ILON SAK IS I(18. RANOSIT aS(i. DM4N DUNG BOG 195. ILOP BURI (62 1.8(62 (19 T. RANONG RN12. DAN K(HUN ((LANG 810 196. ILOWER KAE PING LMP ISO18. RANOT RA13. BAN MA SAN DMS 197. IMAE CHAEMI _____ Mc (SI. RATCHADURI 1.263 RB(.2&314. DAN PHAI Dpi I98. IMAE CHAM IICN 182. RATCHADURI POWER PLANT RBPP'

(5. BAN P0140 (62 BP162 ~~~~~~99. IMAE HONG SON (*4 183. RATCHADAPHISEX RPS(6. BAN SAKITI OST I(00. IMAE K(HAM ( 10 (4. RAYONG 1.263 RYI.2&317. BAN YANG BYG 10I. IMAE KOKl hIKK (85. Rol ET REIe.a KAG(API OK (02. MAE RUM LUANG (flEA) 111( ISE. SADA Y01 say19. BANC LAIlUNO DL (03. MAE KUANC __K__ 187_SADA_SD20. BAN LANG 51L0 (04. MAE LAMA LUANG (ILL (88. SAl NOI01N21. BANG "UIN MAK 0BMN (05. MAE MOH 1.263 (611,263 (59. SAI BURl _____

22. BAN PA-IN (62 81162 106. MAE MON MINE HH. 90 SAKONM KNAHON (6223. BANG PAKONG S~~~~~~~PK 107. MAE MOAT 1MNG (91. SALOKDAT L

?4. BANG PHLI DPI (08. MAE SA-NGA MISN i92. SAM PHRAN 42 (A62?5. BANGKO SAOA BSP (09. MAE SMINO(SR 193. SAMUTI SAJIHOM (.263 SNI.2&3?r. BEANGKK I40 S (0. IMAE SOT MS (94. SAMDJ SONGKHRAM s

11. BElONG S~~~~~~~~~T (III. IMAE TAENO 1170 (95. SAN KAIPHAENGSK18. SHUMIDOL 05~~~~~~~s 1(12. IMAHA SARAXHAMI Ma 196. SAMGKHA r19. 00 WIN ~~~~ ~~~~~OWN ((3. MANONOMi MR 191. SAl ADURI (62SR2

50. DUNG ((AN 61(1 ((4. MAP TA PHUT HIP (98m SAF.kBURI 364 __R3_4

SI. DlUNG SAM PHANi DOS (IS. MiUKOAH4AN (2 (10(6& 2" (199. SAITAJ4IP (62 SH(6252. DUJRI RAM DR (16. NA KAE (OUT OF SERVICE) NE 200. SATIJN Stu(3. CHA-AM CA Ill. NAKHON GHAISJ NGS 201. SAb(ANKHALO((S(4. CHACHOENOSAD cc liD. NAKNHO NAYOK NT 202. SAVANNA((HET SIN-IS. CHAYNG MATTHAJIA GNU ((9. NAICHON PATNOtI NPT 1203. Si-RAGHA SC56. CHAI DADAN coo 120. -NAKHON PHAINOM NN 204. ISI SA ((ET SSST. CHAIYAPHUII GYP 121. IN&KHOM RATCHASIHA 162 NR(62 205. SiN(iiUSI$S. CHANTHADURI CT 122. NAKHOM SAWAN MS 206. .SING BURl Si(9. CHIANG ((AN CK(1 (23. NAKCHON Si THAISIARAT NT 201._ SIN PUN SPU(0. CHIANG MAl 1.263 CH11.243 (24. HMA CHOEN MCE 208. SIRIKIT SK12. CHOAN AHAI CR (25. NAMl CHOM NCN 209. SIRINOHORN SAD'2. CHOM BHAG cci 126. NAhI HAENG MHA 210. SOIIDET so

3. CHOM DUNG ~~~~ ~~~~COG 127. NAM ((HEK NAM 211. SONG((HLA SKIi4. CHUM THONG 070 (28. NAM LOEI NIE 212. 50o!rf OANGOKOK so15. CHOMI THIEM CTN 129. NAM MAN NM 213. $011114 rHON BURl STD,6. CHOM DURl co (130. INAIl NGAO U____ NMA 214. SRi1HAOARIND SNR7. CHONG KLAM CNK 1131. MNAM NGUM 1MGO 215. SUITIiOTHAI ST8. CHOMG (EK CSK (132. INAIl PAl MP( (.SI[IKI( U

9. CHULADHORM O~~~~~~~LD (133. [NAIM PHONO (12 P2 H 2(7. Su,;-IAN DBUAl SP-0. CHUM PHAE CPA (134. INAI PUNMG Np 218. SURTAT tHANI SRTI1. CHU(PHON OP ' (35. NAIl SAM 14SN 219. SUIIN Su2. OET UDOM OD 136. NMAI SU MAS 1220. TA4~ (62 TAI&23. DOEMMANO NANGDUAT DMN (37. NMAI THEUN NTH1 1221. TAI,MLI (62 1K(1624. FANG FA 138. MAIl FHEIIM 2 14112l 222. tA1(UA PA TPS. GREATER BANGKOK D(KK 139. HAM YUAIl NYu 223. TA "DON1 111

5. HAT YAI (12 111(62 (~~~~~~~~40. MAN NA 224. THAKIHEKNK7 .HONG SA _SA_14__NRA___W__W_25__HA_ANGT_

8. HOUA HOM tHO (142. 14014 DUA LA"I PHU 1401 226. THP.LAN (.263 T11.2639. HUA HIM NH~~~~~~~~m 143. MOf(NO CHOK *OO 227. fTHAP 711AM F

0. HUAI KUM HK_14_NN_MNNH 28_TA_AO_T1. HUAI NGAED HNG (45. NONG K(HAl 1K 229. THA THUNGMA T2. HUAI PI4UKHI HPK 146. NORTH BANGKOK NB 1230. THAT PHANOII3. HUAI SAK HSK (47. NUCLEAR-4. KADIN BURl XBSD 148. 0ON MUCH ON 232. IHEPIIARAI(TPS. ((AENG ((RUNG K(KU (49. PAXI CHONG PCH 233. THEUN-HINBOUNTHP6. K(AENG SUA TEN KT 15.PXHMPN 24 H NN KP. ((ALASIN P 25 HE E5. KA(IPHAENGPHET ((P (52. IPATHUM THANI PT 236. THOENG TMO9. KAW04AENG sAEm KS5 153. IPATTANI PIN 237. THUMb SONG TS0. KANCHANADURI KB 154. IPHACHI PH 1235. TRANG TO1. KAEMG KAACHAN K((C 155. IPHANAT MIKHOMI FNN1 1239. TRAT TRL._ KANTANG ((1 156. IPHANG KNHON PHK 20 BLAAI J

3. KANTHARAIAK ((I~~~~~KL (57, PH4AMNGNA ______ PM 24(.- UBON RAICHATHANI (42 UBI&24. ((HANOM KM (58. IPHATIHALUMO PU 242. -UDON THJANI (42 UDIQ6S. ((MAO LAEM ((HL (59. (PHATAJ(KHAPHUNi PHISAI P1K 243. UPPER nAE PING UMPS. ((HIONG tHAl ((L11 (60. PHAYAO PY 244. UPPER PA SAKT UPSr. K(HLONG NOAE KNMEI 11. PHETCHASUN PE 245. U THONG UTO8. KNOK K(LOI KKL(1 (62. PHETCHADUAI Pe 246. UTTARADIT __UT

9. (HON K(AEN (.2&3 ((((.263 (63. PHICHIT PG 241. WANG 1O40W0. ((HONG ((O (4 HITSANULOK( (.6 112 248. ATHANA(O (INWKI. ((IRIDHARNIHUAI SAPHAN HIM) (CR0 (85. PHON PO 1249. (IIENG h(AENG WHOG2. KLAENG ((LA 166. PHON THONG ____ POT 1250. XESET X(SE3 .KRABI K(A 167. PHAA PHUITHADAT P5 21 AAT4. (((J KUD I6.PAEPA 1252. ITASOTHON YT

iEVISION 1,3 ~ ~ ~21 3- IAANS!IISSION SYSTEM PLANNING DIVISION

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