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ENERGY MARKET AUTHORITY Review of the Vesting Contract Technical Parameters for the period 1 January 2015 to 31 December 2016

25 July 2014

PA Regional Office:

PA Consulting Group Level 13, Allied Nationwide Finance Tower, 142 Lambton Quay, Wellington 6011, New Zealand Tel: +64 4 499 9053 Fax: +64 4 473 1630 www.paconsulting.com

Version no: 9.0

Prepared by: Rohan Zauner Document reference:

This report is prepared for the EMA in connection with PA's review of the Vesting Contract price

parameters for 2015 and 2016. PA has prepared this report on the basis of information supplied by the

EMA, data which is available in the public domain, and proprietary information. Whilst PA has

prepared this report with all due care and diligence and has no reason to doubt the documentation and

information received, it has not independently verified the accuracy of the information and documents

provided to us by EMA. This report does not constitute any form of commitment on the part of PA.

Except where otherwise indicated, the report speaks as at the date hereof.

Third party use

PA makes no representation or warranty, express or implied, to any third party as to the contents of

this report and its fitness for any particular purpose. Third parties reading and relying on the report do

so at their own risk; in no event shall PA be liable to a third party for any damages of any kind,

including but not limited to direct, indirect, general, special, incidental or consequential damages

arising out of any use of the information contained herein.

DISCLAIMER

PA Consulting has been engaged by the Energy Market Authority (EMA) to provide recommended values for the financial and technical parameters of the Vesting Contracts for electricity generation in Singapore for the period 2015 and 2016. Jacobs SKM has been engaged by PA Consulting to provide the technical parameters.

LRMC technical parameters

The following values are recommended by SKM for use in the Vesting Contract parameters for 2015-

16.

Table 1 Summary of recommended technical parameters

Item Parameter 2015-16 Value

6 Economic capacity of the most economic

technology in operation in Singapore (MW)

386.67 MW net at 32oC

7 Capital cost of the plant identified in item 6

($US/kW)

936.79 USD/kW

8 Land, infrastructure and development cost of the

plant identified in item 6 ($Sing million)

SGD 151.27M

11 HHV Heat Rate of the plant identified in item 6

(Btu/kWh)

7103.8 btu/kWh net HHV

12 Build duration of the plant identified in item 6 (years) 2.5 years

13 Economic lifetime of the plant identified in item 6

(years)

24 years

14 Average expected utilisation factor of the plant

identified in item 6, i.e. average generation level as

a percentage of capacity (%)

64.4%

15 Fixed annual running cost of the plant identified in

item 6 ($Sing)

23.83M SGD

16 Variable non-fuel cost of the plant identified in item

6 ($Sing/MWh)

6.56 SGD/MWh

EXECUTIVE SUMMARY

CONTENTS

DISCLAIMER

EXECUTIVE SUMMARY

LRMC technical parameters

1 INTRODUCTION

1.1 Financial parameters

1.2 Disclaimer

2 PERFORMANCE PARAMETERS

2.1 Existing generators

2.2 Generating technology

2.3 Capacity per generating unit

2.4 Impact of gas compression and resulting net capacity

2.5 Heat Rate

3 CAPITAL COST

3.1 Method

3.2 Initial capital cost 25

3.3 Through-life capital costs

3.4 Land and Site Preparation Cost

3.5 Connection Cost

3.6 Owner's costs after financial closure

3.7 Owner's costs prior to Financial Closure

4 OPERATING COSTS

4.1 Fixed annual running cost

4.2 Variable non-fuel cost

5 OTHER PARAMETERS

5.1 Build duration

5.2 Economic life

5.3 Average expected utilisation factor

6 RESULTS – VESTING CONTRACT PARAMETERS

6.1 Introduction

6.2 Summary of technical parameters

6.3 Calculated LRMC

APPENDICES

A PRESCRIBED PROCEDURES

B ECONOMIC LIFE

C THERMODYNAMIC ANALYSIS

INTRODUCTION

The Energy Market Authority (EMA) has implemented Vesting Contracts to control market power of generation companies in the National Electricity Market of Singapore. The parameters for setting the Vesting Price associated with these contracts are to be reviewed every two years. The current review relates to the setting of these parameters for 1 January 2015 through to 31 December 2016.

EMA has engaged PA Consulting to:

• Conduct a comprehensive review and recommend the value of each vesting contract technical parameter (items 6 through 8 and 11 through 16 in section 2.3 of the Vesting Contract Procedures) for the setting of the vesting price for the period 1 January 2015 to 31 December 2016; and

• Review the financial parameters, which are presented in a separate report.

PA Consulting has engaged Jacobs SKM to provide the technical parameters.

This review of the vesting contract parameters follows the method adopted by SKM (now part of Jacobs group) in the review of parameters for the period 1 January 2013 to 31 December 2014 (the “2013-14” review).

The parameters of the Vesting Contract determine the Vesting Price associated with these contracts and are reviewed every two years, covering the subsequent two-year period. The sixth of these two yearly reviews is the subject of this project, covering the period 1 January 2015 to 31 December 2016.

1.1 Financial parameters

Financial parameters for use in the technical parameter analysis are shown in Table 2.

Table 2 Finance parameters applied

Parameter Value Notes

WACC 6.82% post-tax, nominal

5.92% pre-tax, real

Advised by EMA.

CPI 2.17% Average year-on-year core inflation,

Mar 2014, Apr 2014, May 2014.

Trend data is shown in Figure 1

Gas price $19.79 SGD/GJ Advised by EMA.

Exchange rates 1.2580 SGD/USD

1.7346 SGD/EUR

Average bid and ask, daily, Mar

2014, Apr 2014, May 2014. Trend

data is shown in Figure 2.

Figure 1 Singapore CPI data1

1 Monthly data Department of Statistics, Singapore, http://www.singstat.gov.sg/news/news/cpifeb2014.pdf and earlier editions

-

1.0

2.0

3.0

4.0

5.0

6.0

Ye

ar

on

ye

ar

%

CPI (Y-o-Y)

MAS core CPI (Y-o-Y)

Figure 2 Foreign exchange rate trends

1.2 Disclaimer

This report has been prepared for the benefit of EMA for the purposes of setting the vesting contract

price for the 2015 to 2016 period. This report may not be relied upon by any other entity and may not

be relied upon for any other purpose.

1.0

1.1

1.2

1.3

1.4

1.5

1.6

1.7

1.8

1.9

2.0

1/01/2010 1/07/2010 1/01/2011 1/07/2011 1/01/2012 1/07/2012 1/01/2013 1/07/2013 1/01/2014 1/07/2014

fx r

ate SGD/USD

SGD/EUR

The technical performance parameters for the notional new entrant plant are estimated in this Section.

2.1 Existing generators

Parameters for the existing generation fleet in Singapore2 are shown in Table 3.

Table 3 Registered capacity, large CCGT units

Large CCGT units Reg. Cap,

MW

Date Licence

SNK CCP 1 (Senoko) 425 1996 EMA/GE/012







SembCorp Cogen SKACCP1 392.5 2001 EMA/GE/004



TUAS Stage 2 CCP1 367.5 2001 EMA/GE/009



TUACCP4 367.5 2005 EMA/GE/009

TUACCP5 405.9 2014 EMA/GE/009

Power Seraya CCP1 368 2002 EMA/GE/016



2 http://www.ema.gov.sg/page/115/id:129/

2 PERFORMANCE PARAMETERS

Large CCGT units Reg. Cap,

MW

Date Licence


Keppel Merlimau Cogen GRF 3 420 2013 EMA/GE/006

Keppel Merlimau Cogen GRF 4 420 2013 EMA/GE/006

PacificLight Power Unit 1 400 2014 EMA/GE/005

PacificLight Power Unit 2 400 2014 EMA/GE/005

2.2 Generating technology

The parameters for the existing relevant power stations in Singapore are given in Table 4:

Table 4 Existing Singapore station parameters (large F class CCGT units)3

Power

station

Train

capacity

MWe

Number of

trains

Total station

Frame F

capacity

MWe

CCGT

technology

GT type Original

Equipment

Manufacturer

(OEM)

Senoko

Converted

CCGT

365 3 1095 Type F GT26 Alstom

Senoko

repower

(CCP6&7)

431 2 862 Type F M701F Mitsubishi

TUAS CCGT 367.5 4 1470 Type F M701F Mitsubishi

405.9 1 405.9 Type F GT26 Alstom

Seraya

CCGT

368

364

370

370

4 1472 Type F V94.3A

(SGT5-

4000F)

Siemens

Sembcorp

Cogen4

392.5 2 785 Type F 9FA General

Electric

Sembcorp

Cogen

403.8 1

(committed)

400 Type F GT26 Alstom

Keppel

Merlimau

420 2 840 Type F GT26 Alstom

3. KEMA 2009 op cit. Adjustments based on licensed capacity (EMA) as per Table 3 and as updated by SKM

4 Evaluations have been made based on CCGT performance only

Power

station

Train

capacity

MWe

Number of

trains

Total station

Frame F

capacity

MWe

CCGT

technology

GT type Original

Equipment

Manufacturer

(OEM)

PacificLight

Power

400 2 800 Type F SGT5-

4000F

Siemens

The Vesting Contract procedures published by EMA5 indicate that:

The EMA implemented Vesting contracts on 1 January 2004 as a regulatory instrument to mitigate the

exercise of market power by the generation companies (“Gencos”). Vesting Contracts commit the

Gencos to sell a specified amount of electricity (viz the Vesting Contract level) at a specified price (viz

the Vesting Contract price). This removed the incentive for Gencos to exercise their market power by

withholding their generation capacity to push up spot prices in the wholesale electricity market.

Vesting Contracts are only allocated to the Gencos that had made their planting decisions before the

decision was made in 2001 to implement Vesting Contracts.

And:

The Allocated Vesting Price approximates the Long Run Marginal Cost (LRMC) of a theoretical new

entrant that uses the most economic generation technology in operation in Singapore and contributes

to more than 25% of the total demand.

The underlying concept of LRMC is to find the average price at which the most efficiently configured

generation facility with the most economic generation technology in operation in Singapore will cover

its variable and fixed costs and provide reasonable return to investors. The plant to be used for this

purpose is to be based on a theoretical generation station with the most economic plant portfolio (for

existing CCGT technology, this consists of 2 to 4 units of 370MW plants). The profile of the most

economic power plants is as follows:

– Utilises the most economic technology available and operational within Singapore at the time.

This most economic technology would have contributed to more than 25% of demand at that

time.

– The generation company is assumed to operate as many of the units of the technology

necessary to achieve the normal economies of scale for that technology.

– The plants are assumed to be built adjacent to one another to gain infrastructure economies of

scale.

– The plants are assumed to share common facilities such as land, buildings, fuel supply

connections and transmission access. The cost of any common facilities should be prorated

evenly to each of the plants.

– The plants are assumed to have a common corporate overhead structure to minimise costs.

Any common overhead costs should be prorated evenly to each of the plants.

The technology that should be selected according to these criteria would be CCGT units based on "F"

class gas turbines. The existing large CCGT/Cogen plants in Singapore are based on "F" class gas

turbine technology (refer Table 4) which together comprise more than 50% of the generation capacity

of Singapore.

5 Energy Market Authority, "EMA's procedures for calculating the components of the vesting contracts", March 2011, Version 1.7

Jacobs SKM expects that any new plant in Singapore would be optimised for performance at the site

Reference Conditions. For this review it is taken that the site Reference Conditions6 are the all-hours

average conditions of:

• 29.5ºC dry bulb air temperature,

• 85% Relative Humidity (RH);

• Sea-level;

• 29.2ºC cooling water inlet temperature7.

Operation at other ambient or sea water conditions represents off-design operation. This includes

operation at the ambient conditions specified in the Singapore Market Manuals for the Maximum

Generation Capacity, which includes an ambient temperature of 32ºC. Consistent with the treatment

in 2010 for the 2011-12 review and 2012 for the 2015-16 review, a correction factor for the plant's

capacity to 32ºC has been applied.

As shown in Table 4, the Singapore market includes "F" class units from each of the following OEMs8:

• Alstom;

• Siemens;

• General Electric (GE); and

• Mitsubishi.

The market for supply of such plants is competitive and it generally cannot be determined, without

competitive bidding for a specific local project, which design is the most economic generation

technology on an LRMC basis for new built plant. It is often the case for example that the

configuration offered with the lowest heat rate is the bid with a higher capital cost. In order to model

the performance of the most economic generator it is therefore considered appropriate to consider the

performance of all these OEM's appropriate "F" class CCGT configurations and to use an arithmetic

average of the performance parameters of each of these OEMs' plants in CCGT configuration9.

In order to estimate these performance parameters, the GTPro/GTMaster10 (Version 24 Release dated

28 May 2014) thermodynamic analysis software suite was applied. Representative schematics of the

resulting configurations are shown in Appendix C.

2.3 Capacity per generating unit

The generation capacities of new entrant CCGT configurations, on a clean-as-new condition, and at

the Reference Conditions of 29.5ºC air temperature are given in Table 5. Note that upgrades of gas

turbine technologies occur frequently and judgement must be applied as to whether a new entrant

developer would choose the very latest announced version for a project in Singapore or not. In this

review SKM has decided not to apply the very latest announced models of the Mitsubishi gas turbine

(the 701F5) and the Alstom GT26 2011 upgrade but to instead select the variants that have been

available in the market for a longer time (considering commercial operating experience).

New designs beyond “F” class technology are now available from most OEMs. For example “H” and

“J” classes. A new entrant would likely consider these later models, noting the relatively high gas

price in Singapore favours selection of configurations with the best efficiency. These new designs

offer significantly higher efficiency than the units operating in Singapore at present and than their F-

class equivalents which have evolved over time and are available today. However, the procedure

indicates that the Allocated Vesting Price approximates the Long Run Marginal Cost (LRMC) of a

6 As applied in the 2013-14 review

7 EMA has provided the average seawater temperature for TUAS area to be approximately 29.2 ºC

8 Original Equipment Manufacturers

10 TM, Thermoflow, Inc.

theoretical new entrant that uses the most economic generation technology in operation in Singapore

and contributes to more than 25% of the total demand. Thus it is interpreted that the procedure

requires evaluation of “F” class units which are currently offered by the OEMs.

Table 5 Generation capacity of new entrant CCGT units (clean-as-new at Reference Conditions, excluding

gas compression impacts)

Configuration Gross MW Net MW

Frame 9FB (now

designated 9F.05)

408.2 399.6

M701F4 444.6 435.7

GT26 414.3 405.8

SGT5-4000F 389.2 381.4

Average 414.1 405.6

This thermodynamic modelling includes all corrections necessary for:

• Ambient and sea water conditions of 29.2ºC;

• Boiler blow-down; and

• Step-up transformer losses.

No further allowances need to be made for these factors except as discussed below regarding

ambient temperature. The loads incorporated into GTPro are shown in Table 6.

Table 6 Auxiliary loads incorporated within GTPro models, kW

SGT5-

4000F

GT26 Fr 9FB 701F4

GT fuel compressor(s) (Note separately

calculated)

0 0 0 0

GT supercharging fan(s) 0 0 0 0

GT electric chiller(s) 0 0 0 0

GT chiller/heater water pump(s) 0 0 0 0

HRSG feedpump(s) 2391.4 2847.4 2859.5 2730.4

Condensate pump(s) 251.6 282.1 273.5 280

HRSG forced circulation pump(s) 0 0 0 0

LTE recirculation pump(s) 0 0 0 0

Cooling water pump(s) 1013.9 1174.6 1129.4 1163.2

Air cooled condenser fans 0 0 0 0

Cooling tower fans 0 0 0 0

HVAC 50 50 50 55

SGT5-

4000F

GT26 Fr 9FB 701F4

Lights 90 90 100 110

Aux. from PEACE running motor/load list 953.8 971 1001.2 1140.2

Miscellaneous gas turbine auxiliaries 584.5 566.8 600 654.1

Miscellaneous steam cycle auxiliaries 275.5 325.6 313.5 310.4

Miscellaneous plant auxiliaries 194.6 207.2 204.1 222.3

Constant plant auxiliary load 0 0 0 0

Program estimated overall plant auxiliaries 5805 6515 6531 6666

Actual (user input) overall plant auxiliaries 5805 6515 6531 6666

Transformer losses 1945.9 2071.7 2041 2223.1

Total auxiliaries & transformer losses 7751 8586 8572 8889

The impact of gas compression requirements is discussed separately below (Section 2.4).

The capacities and heat rates of operating gas turbine and CCGT power plants degrade from the time

the plant is clean-as-new11. The primary drivers for performance degradation are fouling, erosion and

roughening of the gas turbine compressor blades and material losses in the turbine section. A CCGT

plant has a slightly reduced degradation profile than a simple cycle gas turbine installation due to

partial recovery of the losses suffered by the gas turbine in the steam cycle, and that the gas turbine

only comprises approximately 2/3 of the plant output. This degradation effect is typically described as

having two components:

"Recoverable" degradation is degradation of performance that occurs to the plant that can be

recovered within the overhaul cycle. Recoverable degradation can be substantially remediated by

cleaning of air inlet filters, water washing of the compressor, ball-cleaning of condensers and the like.

These cleaning activities are typically undertaken several or many times within a year depending on

the site characteristics and the economic value of performance changes; and

"Non-recoverable" degradation is caused by the impacts of temperature, erosion and corrosion of

parts within the plant. This type of degradation is typically substantially remediated at overhaul when

damaged parts are replaced with new or refurbished parts. Because the typical industry repair

philosophy uses an economic mix of new and refurbished parts within overhauls, it is typically the case

that not all of the original clean-as-new performance is recovered at the overhauls.

The average capacity reduction due to recoverable degradation is estimated at 1%. That is, the

degradation amount varies from approximately zero to approximately 2% over the cleaning cycle.

Additional to this, an allowance for the non-recoverable degradation of capacity should be made.

These typically have the form similar to that shown in Figure 3. Degradation rates for base and

intermediate loaded CCGT units are not considered to be materially affected by load factor or capacity

factor.

11 Refer GE publication “Degradation curves for Heavy Duty Product Line Gas Turbines” for example

Figure 3. Form of CCGT recoverable and non-recoverable degradation

Based on plants operating up to 93.2% of hours in the year12, the degradation allowance of 3.06% for

average capacity degradation over the plant's life is suggested (calculated as a weighted average

using the pre-tax real discount rate to weight each year in the plant’s life).

Variations in ambient temperature affect the capacity of the generating units. The modelled impacts of

variations in ambient temperature on the new entrant configurations and the average impact across

the four modelled configurations are shown in Table 7 and Figure 4.

Table 7 Variation in net power output with ambient temperature (relative to Reference Conditions)

Config. Ambient temperature (dry bulb), ºC

0 5 10 15 20 25 30 35 40

GT26 108% 107% 106% 104% 103% 102% 99% 97% 94%

Frame 9FB 110% 110% 109% 108% 105% 103% 100% 95% 89%

701F 112% 110% 108% 106% 104% 102% 100% 98% 95%

SGT5-

4000F

110% 110% 109% 108% 105% 103% 100% 97% 94%

Average 110% 109% 108% 107% 104% 102% 100% 97% 93%

12 Which is the estimated Available Capacity Factor for the plant

0.0%

0.5%

1.0%

1.5%

2.0%

2.5%

3.0%

3.5%

4.0%

4.5%

0 5 10 15 20 25

De

gra

da

tio

n f

rom

cle

an

-as-

-ne

w

Years

Power degr

HR degr

Figure 4 Effect of ambient temperature on power output

The correction factor for operation at 32ºC relative to the Reference Conditions of 29.5ºC is a

reduction in capacity of 1.48% (averaged over the four models), or 6.02MW. Note that for variations of

ambient relative humidity between 75% and 95% there is negligible difference in the performance of

CCGT plants with once-through cooling.

The electrical connection cost is based on the maximum net plant output, which is at an ambient

temperature of 24.7ºC. At this condition the average net output of the four OEMs’ plants is calculated

to be 416.24MW/unit.

2.4 Impact of gas compression and resulting net capacity

Gas compression is now required for new entrant “F” class CCGT plants in Singapore.

Three of the CCGT configurations noted use natural gas at approximately 30 barg and one

configuration (the GT26) uses natural gas at approximately 50 barg. The gas compressor power

requirements calculated for the relevant gas turbines at varying gas pressures are shown in Figure 5.

An additional 7 bar pressure drop allowance from the system pressure measurement point to the site

boundary (as included in GTPro) is included in the calculation.

80%

85%

90%

95%

100%

105%

110%

115%

120%

0 5 10 15 20 25 30 35 40

Po

we

r, %

of

Po

we

r a

t R

efe

ren

ce C

on

dit

ion

s

Ambient dry bulb temperature

GT26

9FB

701F

4000F

Average

Figure 5 Gas compressor power requirements for relevant gas turbines

Data for gas pressures in the TUAS area of Singapore is shown in Figure 6, for the period from 2010

to 2014. The Network 1 pressure may be downstream of a regulator in which case the upstream

pressure will be higher.

Figure 6 Gas pressures in TUAS area, 2010 to 2014

-

500

1,000

1,500

2,000

2,500

3,000

20 25 30 35 40 45 50 55 60 65

Ga

s co

mp

ress

or

po

we

r, k

W

Network gas pressure, Barg

GT26

701F

SGT5_4000F

9FB

Average

Note: Allowance for 7 Bar

pressure drop from network

reference point to GTPro

reference point included

0

500

1000

1500

2000

2500

3000

3500

4000

4500

Jun

20

10

Jul

20

10

Au

g 2

01

0

Se

p 2

01

0

Oct

20

10

No

v 2

01

0

De

c 2

01

0

Jan

20

11

Feb

20

11

Ma

r 2

01

1

Ap

r 2

01

1

Ma

y 2

01

1

Jun

20

11

Jul

20

11

Au

g 2

01

1

Se

p 2

01

1

Oct

20

11

No

v 2

01

1

De

c 2

01

1

Jan

20

12

Feb

20

12

Ma

r 2

01

2

Ap

r 2

01

2

Ma

y 2

01

2

Jun

20

12

Jul

20

12

Au

g 2

01

2

Se

p 2

01

2

Oct

20

12

No

v 2

01

2

De

c 2

01

2

Jan

20

13

Feb

20

13

Ma

r 2

01

3

Ap

r 2

01

3

Ma

y 2

01

3

Jun

20

13

Jul

20

13

Au

g 2

01

3

Se

p 2

01

3

Oct

20

13

No

v 2

01

3

De

c 2

01

3

Jan

20

14

Pre

ssu

re,

kP

ag

N2 Tuas Power

N1 Tuas Power

Table 8 Gas pressure trends, kPag

Year Network N1, TUAS Network N2, TUAS

Min Avg. Min Avg.

2010 3,860 3,916 2,303 3,202

2011 2,193 3,918 2,285 3,233

2012 3,773 3,901 2,406 3,518

2013 3,849 3,935 2,369 3,518

The data indicates that gas compression is sometimes required under current conditions. Should the

system pressures reduce further (e.g. because of load growth) then gas compression would be

required more often.

For the purposes of this review it is assumed:

• Gas compressors would be incorporated in a new plant in the TUAS View vicinity;

• The specification of the compressors would allow for further reductions in local gas pressures from

those presently seen. It is assumed they would be capable of operating from a site boundary gas

pressure of 17 Barg; and

• The average pressure at the site boundary during operation is 35.2 Barg in the relevant period,

being the average pressure in the Network 2 in 2013.

On this basis the calculated average gas compressor auxiliary/parasitic load impact is 0.529 MW per

unit based on the averaged pressure requirements of the four gas turbine models under consideration.

The resulting net capacity calculation after considering the above is shown in Table 9.

Table 9 Generation capacity of new entrant CCGT units

Parameter/factor MW

Gross capacity (clean-as-new, reference conditions) 414.09

Less parasitics = net capacity at Reference Conditions (clean-as-new) -8.5 = 405.6

Less allowance for gas compression -0.529

Adjust for 32ºC maximum registered capacity (-1.48%) -6.02

Adjust for average degradation (-3.06%) -12.42

Net capacity 386.67

2.5 Heat Rate

The heat rates of new entrant CCGT configurations, on a clean-as-new condition, and at the

Reference Conditions of 29.5ºC air temperature are given in Table 10.

Table 10 Heat rate of new entrant CCGT units (clean-as-new at Reference Conditions excluding gas

compression)

Configuration Net HR, LHV,

GJ/MWh

Net HR, HHV,

GJ/MWh

Net HR,

LHV,

Btu/kWh

Net HR,

HHV,

Btu/kWh

Frame 9FB 6.265 6.948 5.938 6.586

M701F 6.296 6.982 5.968 6.618

GT26 6.237 6.917 5.912 6.556

SGT5-4000F 6.284 6.969 5.956 6.606

Average 6.271 6.954 5.944 6.591

This thermodynamic modelling includes all corrections (within GTPro) necessary for:

• Ambient conditions and average sea water temperature of 29.2ºC;

• Boiler blow-down; and

• Step-up transformer losses.

No further allowances need to be made for these factors except as discussed below regarding

ambient temperature and gas compression impacts.

As noted in Section 2.3 above, heat rates for CCGT plants are also subject to degradation. A

weighted average heat rate degradation over the plant's life of 1.90% is estimated (weighted by the

pre-tax real discount factor for each year).

Variations in ambient temperature affect the heat rates of the generating units. The modelled impacts

of variations in ambient temperature on the new entrant configurations and the average impact across

the four modelled configurations are shown in Table 11 and Figure 7.

Table 11 Variation in net heat rate with ambient temperature (relative to Reference Conditions)

Ambient temperature (dry bulb), ºC

Config. 0 5 10 15 20 25 30 35 40

GT26 100.6% 100.4% 100.2% 100.1% 100.0% 100.0% 100.0% 100.0% 100.3%

Frame 9FB 101.1% 100.7% 100.3% 100.0% 99.9% 99.9% 100.0% 100.4% 101.4%

701F 100.5% 100.4% 100.3% 100.3% 100.2% 100.1% 100.0% 100.1% 100.2%

SGT5-

4000F

101.8% 101.3% 100.8% 100.3% 100.2% 100.1% 100.0% 100.0% 100.2%

Average 101.0% 100.7% 100.4% 100.2% 100.1% 100.0% 100.0% 100.1% 100.5%

Figure 7 Impact of ambient temperature on heat rate

Note that for variations of ambient relative humidity between 75% and 95% there is negligible

difference in the performance of CCGT plants with once-through cooling.

The use of fuel by the plant will reflect average operating conditions and hence the heat rate at the

Reference Conditions has been applied. It is not appropriate to consider the Standing Capability Data

criterion for capacity (i.e. at 32ºC) to also apply for the plant's heat rate except in as much as it impacts

on the average part load factor as discussed below.

Whenever the power plant is operated at less than the Maximum Continuous Rating (MCR) of the

plant at the relevant site conditions, the heat rate is affected. The modelled variation in heat rate with

the part load factor of the plant is shown in Table 12 and Figure 8

Table 12 Variation of heat rate with part load (%)

Power 55% 60% 65% 70% 75% 80% 85% 90% 95% 100%

Average

HR

relative to

full load,

110.0 108.1 106.5 105.1 104.0 102.9 102.0 101.2 100.5 100.0

95%

100%

105%

0 10 20 30 40

HR

, % o

f H

R a

t R

efe

ren

ce C

on

dit

ion

s

Ambient dry bulb temperature

GT26

9FB

701F

4000F

Average

Figure 8 Variation of heat rate at part load

EMA have advised that the part load factor is to be calculated based on the Plant Load Factor (PLF).

The PLF of 64.4% is discussed in Section 5.3. Applying the Available Capacity Factor of 93.2% (ie

planned and unplanned outage rate is 6.8%) and assuming there are no economic shuts or part load

conditions, the calculated part load factor is 64.4% / 93.2% = 69.1%. The apparent part load factor for

the plant's performance is slightly reduced since the registered capacity would only be 98.5% of the

nominal capacity. The resulting overall part load factor is 68.1%for which the part-load factor for heat

rate would be 5.64%.

An additional adjustment is made to reflect the natural gas used in starts through the year. The gas

usage for starts is estimated at 10 hours of full-load operating equivalent, or 0.1%.

In reviews prior to 2010, an additional allowance on account of regulation service is added to the heat

rate (+0.5%). However, AGC requirement in Singapore is not considered to be materially different from

other jurisdictions, where minor perturbations of output on account of AGC (for those units in the

system providing AGC service) or on droop-control are part of normal operations for which no specific

extra allowance is considered appropriate. Note that the impact of operating the plant at part-load on

account of the need for regulation and contingency reserve ancillary services is already accounted for

within the load factor correction.

An adjustment is applied to account for the gas compressor auxiliary load. As noted in Section 2.4,

the auxiliary load of the gas compression has an impact on net output and also on net heat rate.

The resulting overall heat rate calculated is shown in Table 13.

100%

102%

104%

106%

108%

110%

112%

114%

60% 70% 80% 90% 100%

He

at

rate

, %

of

full

lo

ad

HR

Part load

9FB

701F

GT26

4000F

Average

Table 13 Heat rate of new entrant CCGT units

Parameter/factor Heat rate

Net HR (clean-as-new, reference conditions) - after

recognition of parasitic loads

6.954 GJ/MWh HHV

Adjust for overall part load factor (+5.64%) +0.392

Adjust for average degradation (+1.90%) +0.132

Adjust for starts gas usage (+0.1%) +0.007

Adjust for gas compressor impact +0.010

Adjusted heat rate 7.495 GJ/MWh HHV

Net HR 7,104 Btu/kWh HHV

Capital cost includes:

• Costs of the CCGT generating units, which are typically unitised, each comprising gas turbine generator, HRSG and steam turbine

• facility costs (ancillary buildings, water treatment and demineralisation plant, sea water intake/outfall structures, constructing the jetty for emergency fuel unloading facility and gas receiving facilities) classified under land and site preparation cost in previous reviews,

• emergency fuel facilities classified under land and site preparation cost in previous reviews,

• civil works for the plans, erection and assembly, detailed engineering and start-up costs, and contractor soft costs classified under connection cost in previous reviews and

• discounted through life capital cost classified under miscellaneous cost in previous reviews.

3.1 Method

The capital cost of a new entrant CCGT plant using current costs is assessed using the following

method, shown in Figure 9.

Jacobs SKM has made enquiries to the four OEMs requesting advice on the current specific capital

costs (on a greenfields EPC basis) for a specific generic CCGT configuration that Jacobs SKM use to

compare costs between projects and times on a consistent basis. This is based on a “1+1” single

shaft “F” class unit with mechanical draft evaporative cooling tower and gas-only fuel. This enquiry

was specific for the Singapore region.

Jacobs SKM modelled this configuration within the latest version of the PEACE software included with

the GTPro software suite noted in Section 2.3 above and, using the current regional cost factors in-

built into PEACE for Singapore and other relevant countries, adjusted the PEACE estimate to reflect

the OEM discussions.

Jacobs SKM has considered the latest version of Gas Turbine World Handbook, published in early

2013.

Considering this information Jacobs SKM assesses that the current EPC cost (excluding connections

and on an “overnight basis”) of a "standard" single-unit "F" class CCGT unit for the Singapore location

has reduced by 10% on a USD/kW basis since the previous review (based on net ISO output).

SKM then evaluates whether the regional cost indices within PEACE require adjusting to produce the

assessed market EPC specific cost. In the case of the current review, using Thermoflow version 24,

no adjustment factor was considered necessary. This produced a broadly consistent result with the

expected market price and is consistent with the method employed in the previous review.

Models are then established within PEACE for the configurations being evaluated. These include

once through cooling, dual fuel installation, gas compression, and savings in infrastructure when

shared between multiple units and considering the site reference ambient conditions. This produces a

capital cost estimate for the basic plant.

3 CAPITAL COST

Further calculations are made to estimate costs for the site specific costs which cannot be modelled in

PEACE by direct calculation or by escalating from the previous review.

Figure 9. Capex estimation method

This method is consistent with the 2011-12 and 2013-14 reviews.

Evaluate capex for Reference

Plant using OEM discussions

and other projects

Evaluate capex for Reference

Plant using PEACE program

with current cost factors for

Reference Plant location

Is PEACE

capex approx.

equal to

market cost?

Calculate scale factor to apply

to PEACE to bring to market

cost. Use for all PEACE

models

Model actual plant

configuration and location in

PEACE using scale factor if

applicable. Gives estimate for

EPC cost

Add local costs, connection

costs and through-life capex,

separately calculated

Add owner’s costs

= Total capital cost (excl. IDC)

Yes

No

Jacobs SKM assesses that the capital costs of large CCGT plants for current procurement have

reduced further between the 2013-14 review and this review.

A comparison of data presented in recent editions of the Gas Turbine World Handbook for relevant

gas turbines is shown in Table 14. The various qualifications given in the Handbook should be

considered when evaluating this data.13. Jacobs SKM considers that the Handbooks are not as

directly useful as market soundings and information from other projects because the Handbook

information has a time-delay from the time it was written, it is not geographically specific and scope

differences occur between editions of the Handbook.

Table 14 Gas Turbine World Handbook budget plant prices for CCGT units, USD/kWISO

Gas turbine unit

for a single shaft

CCGT block

Vol. 26

2007-08

Vol. 27

2009

Vol. 28

2010

Vol. 29

2012

Vol. 30

2013

Frame 9FB 520 551 494 536 572

M701F 529 539 491 533 560

GT26 521 549 497 539 Not listed

SGT5-4000F 521 550 497 Not listed Not listed

SKM has also considered the trends in local construction cost parameters for Singapore as shown in

Table 15 and Figure 10.

Table 15 Local construction cost parameters (nominal) for Singapore14

• 2008 2009 2010 2011 2012 2013 2014

CPI (SingStats) 2009=100 99.4 100 102.8 108.2 114.1 115.8 117

Tradesman SGD/h 11.5 12 12 12.5 12.5 12.5 13

Labourer SGD/h 7.5 8 8 8 8.5 9 9.5

Building Price Index (re previous

year)

9% -8% -1% -1% -1% -1% 2%

Industrial factories/warehouses,

owner occ., SGD/m2

1200 1950 1700 1750 1600 1750 1750

Concrete (foundations) SGD/m3 160 160 150 127 137 140 143

Structural steel, UB, UC etc. erected

SGD/t

4500 6000 5200 5280 5230 5200 5300

13 These are “bare bones” standard plant designs and exclude design options such as dual fuel and project specific

requirements, are for sites with minimal transportation costs, site preparation and with non-union labour, and there can be a

wide-range of prices for combined cycle plants depending on geographic location, site conditions, labour costs, OEM marketing

strategies, currency valuations, order backlog and competitive situation.

14 Successive issues of Rawlinson’s “Australian Construction Cost Handbook”, International Construction Costs table

Figure 10 Trends in Singapore local construction cost parameters, 2010 = 100

The apparent local construction costs are slightly above those of 2012 for the 2013-14 review.

For minor capital cost elements of a civil/structural nature, where no new capital cost data is available,

the costs in previous reviews have been escalated from the values used earlier using the "All

Buildings" Tender Price Index published by the Building and Construction Association (BCA) of

Singapore. This same treatment has been applied in this review.

In May 2012 the index was 113.3. The latest value is 123.5. The cost of the minor items is thus

indexed in nominal terms from the previous review by 109%.

3.2 Initial capital cost

Modifications are applied to make the unit cost applicable to this study to reflect different design

features for the Singapore plant, and to consider that the plant required for this review is based on

shared infrastructure within a multi-unit plant. A two-unit plant is assumed. The modifications applied

are:

• Allowances are made for the capital cost of gas compression plant (2 train per unit);

• Civil costs are calculated on a two-unit station basis and then halved;

• Building and structures costs are calculated for a two unit station and then halved;

• The plant is based on a once-through cooling system with the civil costs added separately on a

shared (two-unit) basis;

• Allowance for dual fuel systems for the gas turbines and fuel forwarding from the tanks;

• Allowance for a jetty and fuel unloading facilities is added separately on a shared (two-unit) basis;

• Allowances for fuel tanks are added on a shared (two-unit) basis;

• Adjustment is made for additional security measures as allowed in previous reviews; and

• An adjustment is made for additional inlet filter spares considering the requirements of the

Transmission Code Clause 9.2.5.

0%

20%

40%

60%

80%

100%

120%

140%

2006 2007 2008 2009 2010 2011 2012 2013 2014

Ind

ex

rela

tiv

e t

o 2

01

2

CPI (SingStats) 2012=100

Tradesman SGD/h

Labourer SGD/h

Building Price Index

Industrial factories/wharehouses, owner occ.,

SGD/m2

Concrete (foundations) SGD/m3

Structural steel, UB, UC etc erected SGD/t

The resulting EPC cost for the plant (excluding external connections) is SGD447,395M per unit as

shown in Table 16. This cost is on an "overnight" basis15.

Table 16 EPC capital cost summary (per unit) for 2015-16, with comparison against earlier reviews

Project Cost Summary 2011-12

review

SGD k

2013-14

review

SGD k

2013-14

mid-term

review16

2015-16

review

(current)

SGD k

Comments

I Specialized Equipment 292,400 240,505 231,670 214,780

II Other Equipment 9,668 11,306

184,621

11,389

III Civil 29,106 24,925 25,802 Shared

IV Mechanical 41,306 35,081 33,580

V Electrical Assembly &

Wiring

9,546 5,099 7,123

VI Buildings & Structures 13,217 10,455 9,717 Shared,

except

turbine hall

VII Contractor's

Engineering &

commissioning

19,866 19,302 20,074

VIII Contractor's Soft &

Miscellaneous Costs

(including Contractor's

insurance, contingencies,

margins and preliminaries)

91,099 73,500 69,715

Transport Included Included Included Included

Gas compressors 11,070 13,487 Included 14,831

Adjust for OT C/W system 6,676 6,676 6,450 7,277 Shared

Jetty & unloading 7,972 7,972 9,400 8,690 Shared

Fuel tanks 18,933 18,933 20,750 21,700 Shared

Additional security

measures

0 2,418 2,418 2,635

Inlet filter adjustment

(spares)

0 0 0 82

EPC equivalent capital

cost excl. connections

550,859 469,658 455,309 447,395

15 That is, excluding Interest during Construction (IDC).

16 KEMA report, 2013

Note that there may be additional savings if both units of a two unit plant were procured at the same

time. A small reduction in the costs of the second (and subsequent units if more than two are

procured) which is expected to be of the order of 5% would result due to the sharing of transaction and

engineering costs at both the contractor and owner level. Where the plant procurement is phased by

more than (say) two years, these savings are less likely to result.

If the plant were not phased then consideration would be given to constructing the plant as a "2+1"

block instead of two "1+1" blocks. Technical performance is very similar (including the amount of

output lost when one gas turbine trips). The specific capital cost (SGD/MW) can be materially lower

with a "2+1" arrangement than for two "1+1" blocks. However, this depends on the load net growth

being sufficiently high to justify the additional capacity being constructed immediately after the first

unit. This is not included in this analysis.

3.3 Through-life capital costs

Capital costs of plant maintenance through the overhaul cycle of the gas turbine and steam turbine are

included in Sections 4.1 and 4.2.

Additional capital costs are incurred through the project's life. Actual costs incurred vary considerably

and are based on progressive assessments made of plant condition through the plant's life.

Recommended estimates for this review are given in Table 17:

Table 17 Through-life capital expenditure (per unit)

Area Time within project Estimate, per unit Discounted

equivalent,

SGDM/unit (pre-tax

real WACC=5.92%),

per unit

Distributed control

system (DCS)

15 years 7 SGDM real 3.0

Gas turbine rotor 15 years (100,000 to

150,000 operating

hours)

12.6 SGDM real

(USD10M)

5.3

Total 8.3

The cost of the DCS upgrade depends on the level of obsolescence of related items such as field

instrumentation and associated wiring.

Towards the end of the notional technical life of the plant, if market studies indicated that the plant

may still be economic, studies would be undertaken to evaluate extending the plant's life. The studies

and the resulting costs and resulting life extensions are not included.

3.4 Land and Site Preparation Cost

The land and site preparation cost excludes (i) facility costs (ancillary buildings, demineralisation plant,

sea water intake/outfall structures, constructing the jetty for emergency fuel unloading facility and gas

receiving facilities) and (ii) emergency fuel facilities. These costs have been included under capital

cost for the current review.

The land cost is based on 12.5 Ha of land and 200m of water front for a 2 unit plant. Based on data

published by the JTC Corporation’s Land Rents and Prices, for a 30 year lease, the land price at Tuas

View is between $257 and $321 per square metre (the average has been applied). Water frontage

fees range from $1,280 to $1,920 per metre per year. Using the average annual cost at a discount

rate of 5.92% over 24 years, this gives an equivalent capital cost of $4.05 million. Total capital cost for

land assuming a mid-point land cost is thus $40.17 million.

Site preparation cost is relatively minor. In 2012 for the 2013-14 review, this was assessed to be

$2million. For the current review, we have estimated this to be $2.225 million. Total land and site

preparation costs are thus $42.40million and a per-unit cost of SGD$21.20 million.

3.5 Connection Cost

Connection costs exclude civil works for the plant’s, erection and assembly, detailed engineering and

start-up costs. These costs have been included under the overall capital cost for the current review.

The electrical connection cost has been estimated using a "bottom-up" approach as shown in Table

18. Jacobs SKM has taken into consideration in this assessment the cost of connecting two 400MW

CCGT units using the configuration shown in Figure 11. Depending on the cut-in arrangement, it is

anticipated that a new entrant would use either a 3x500MVA or 2x1000MVA connection to achieve the

“N-1” redundancy requirement. Both the PacificLight and Sembcorp Cogen connections have used

the 3x500MVA arrangement and this is assumed in this review.

Table 18 Electrical connection costs (2 units)

Item Connection Cost Components Cost (SGDM)

1 Standard Connection Charge (to SPPG) SGD

50,000/MW x

832.4MW17

41.6

2 230kV Switchgear GIS

Notes:

Includes switch house but excludes gen

transformer which is included with the

power plant cost

GIS complete

diameters @

breaker and a

half

configuration

+ 2/3 diameter

33.5

3 Underground Cable (based on 3x 500MVA

circuits of 1 km length, direct burial)

Included in

Item 1

0

Total 75.1

Based on the standard Power Grid connection charge, the cost of electrical connection including the

cost of the typical 230kV switchgear is thus estimated to be SGD37.5M per unit.

The connection cost in the 2013-14 review was SGD34.8M/unit.

17 Estimated output for 2 units at 24.7oC ambient

Figure 11 Assumed electrical connection configuration (items per Table 18)

The gas connection costs are escalated (unchanged) from the previous report to SGD14.5M or

SGD7.3M per unit. Over the short distances in the TUAS View area, a 400mm connection would be

readily able to cope with the gas requirements of two units, including at 24.7ºC ambient, and with

relative low velocities and pressure drop.

Total connection cost is thus SGD89.6M, or SGD44.8M/unit.

3.6 Owner's costs after financial closure

The Owner's costs incurred from Financial Closure to the Commercial Operation Date of the plant are

typically allowed as percentage extra costs on the EPC basis plant costs.

SKM recommends the following allowances as shown in Table 19:

Standard Connection Charge

$50,000 per MW

Gen

Gen

1

2

3 3 x 500MVA x 1km

Connection cost components

Table 19 Owner's costs allowances (after financial closure)

Area Percentage of EPC +

connection cost

Cost, per unit (SGDM)

Owners Engineering 3% 14.77

Owners "minor items" 3% 14.77

Initial spares18 2% 9.84

Start-up costs 2% + uplift19 11.44

Construction related insurance etc. 1% 4.92

Total 55.74

Note that the capital cost estimates are made at the 50th percentile of expected outcomes as is

considered appropriate for this application. The EPC estimate includes the contingency and risk

allowances, along with profit margins, normally included in the Contractor's EPC cost estimates. The

extra contingency allowances normally included by the owner within investment decision making

processes to reduce the risk of a cost over-run below 50% are not included.

Owner's engineering costs are the costs to the owner of in-house and external engineering and

management services after financial closure, including inspections and monitoring of the works,

contract administration and superintendancy, project management and coordination between the EPC

contractor, connection contractors and contractors providing minor services, witnessing of tests and

management reporting.

Minor items include all the procurement costs to the owner outside of the primary plant EPC costs and

the electricity and gas connections. This includes permits/licences/fees after Financial Closure,

connections of other services, office fit-outs and the like. This also reflects any site specific

optimisation or cost requirements of the plant above those of a "generic" standard plant covered in

Section 3.2.

Start-up costs include the cost to the owner of bringing the plant to commercial operation (noting that

the actual commissioning of the plant is within the plant EPC contractor's scope). The owner is

typically responsible for fuels and consumables used during testing and commissioning, recruiting,

training and holding staff prior to operations commencing, and for establishing systems and

procedures.

Note that initial working capital, including initial working capital for liquid fuel inventory and for

accounts receivable versus payable, are not included (these are an ongoing finance charge included

in the fixed operating costs of the plant in Section 4.1).

3.7 Owner's costs prior to Financial Closure

At the time of Financial Closure, when the investment decision is being made, the costs accrued up to

that time against the project are "sunk" and are sometimes not included in a new entrant cost

estimate.

Nevertheless, the industry needs to fund the process of developing projects to bring a plant from initial

conception up to financial closure. If these are to be added, the costs can be highly variable. The

allowances should include both in-house and external costs to the owner/developer from concept

18 Note an additional adjustment for extra inlet filter spares is included above in Section 3.2

19 The higher fuel cost in this review than generally applies for other projects SKM has considered that the start-up costs of fuel

used are higher than the standard percentage of capex usually applied. SGD1.6M per unit is added.

onwards including all studies, approvals, negotiations, preparation of specifications, finance arranging,

legal, due diligence processes with financiers etc. These would typically be over a 3 to 5 year period

leading up to financial close. An example of typical allowances based on percentages of the EPC cost

is shown in Table 20.

Table 20 Owner's costs allowances prior to Financial Closure

Area Percentage

of EPC +

connection

cost

Cost, per unit

(SGDM)

Permits, licenses, fees 2% 9.84

Legal & financial advice

and costs

2% 9.84

Owner's engineering and

in-house costs

2% 9.84

Total 29.53

Permits, licences and fees primarily consist of gaining the environmental and planning consents for

the plant.

Legal and financial advice is required for establishing the project vehicle, documenting agreements,

preparing financial models and information memoranda for equity and debt sourcing, management

approvals and due diligence processes.

Owner's engineering and in-house costs prior to financial closure include the costs of conceptual and

preliminary designs and studies (such as optimisation studies), specifying the plant, tendering and

negotiating the EPC plant contract, negotiating connection agreements, attending on the feasibility

assessment and due diligence processes, management reporting and business case preparation, etc.

Project development on a project financed basis sometimes incurs extra transaction costs, such as

swaptions for foreign exchange cover or for forward interest rate cover. These are highly project

specific and not always necessary. No extra allowance is included.

4.1 Fixed annual running cost

An assessment of the fixed annual cost of operating a CCGT station is shown in Table 21.

Note that we have included the gas turbine and steam turbine Long Term Service Agreement (LTSA)

costs as variable costs rather than fixed costs, as LTSA's are normally expressed substantially as

variable costs. The EMA Vesting Contract Procedures state that semi-variable maintenance costs

should be included with the fixed costs amounts. If calculated correctly with the appropriate plant

factor, the same vesting contract LRMC will result. Current LTSA costs for CCGT plants have been

expressed as variable costs in this review and hence these costs are included in the variable cost

section.

Typically, an LTSA only covers the main gas turbine and steam turbine components. All of the

balance of the plant including boilers, cooling system, electrical plant is maintained separately by the

owner outside of the LTSA. The cost of this maintenance is typically considered to be a fixed cost,

and is included in this section.

Table 21 Fixed annual operating cost allowance

Area SGDM for 2 units

Manning 5.37

Allowance for head office services 3.22

Fixed maintenance and other fixed operations20 16.11

Starts impact on turbine maintenance 1.04

Distillate usage impact on turbine maintenance 0.078

EMA license fee (fixed) 0.05778

Working capital (see below) 13.77

Emergency fuel usage 2.20

Property Tax 1.36

Insurance 4.47

Total (for 2 units) per year 47.67

Costs per unit would thus be SGD23.83M per year.

20 Calculated as 3% of the plant capital cost per year excluding the cost attributable to the gas turbine and steam turbine (which

are included in the variable operating/maintenance costs below). These costs need to cover non-turbine maintenance, all other

fixed costs including fixed charges of utilities and connections, service contracts, community service obligations etc.

4 OPERATING COSTS

Manning costs have been estimated based on 45 personnel covering 2 units at

SGD119,306/person/year. The unit rate considers the cost allowed in 2012 for the 2013-14 review

indexed using a factor produced from average remuneration changes in a “chemicals” manufacturing

environment in Singapore (in the absence of a power generation industry index being available) and

MAS Core CPI. The index used is shown in Figure 12.

The personnel include shift operators/technicians and shift supervision as well as day shift

management, a share of trading/dispatch costs if this is undertaken at the station (versus head office),

engineering, chemistry/environmental, trades supervision, trades and trades assistants, stores control,

security, administrative and cleaning support. The cost per person is intended to cover direct and

indirect costs.

Figure 12 Labour cost index21

Head office costs would be highly variable and depend on the structure of the business and the other

activities the business engages in. Only head office support directly associated with power generation

should be included as part of head office costs. The allowance for head office costs is a nominal

allowance (60% of manning cost allowance) for services that might be provided by head-office that are

relevant to the generation services of the plant. These would include (for example):

• Support services for generation such as trading etc.;

• Corporate management and governance;

• Human Resources and management of group policies (such as OH&S, training etc.);

• Accounting and legal costs at head office; and

• Corporate Social Responsibility costs.

21 Indexed produced using SingStats “Yearbook of statistics Singapore 2013 and earlier Table 9.2 and 9.3 "Chemical and

chemical products" manufacturing” average remuneration. MAS core CPI in 2014 year.

0%

20%

40%

60%

80%

100%

120%

1998 2000 2002 2004 2006 2008 2010 2012 2014 2016

Lab

ou

r co

st i

nd

ex

(re

lati

ve

to

20

12

)

The starts impact on turbine maintenance costs accounts for the fact that some gas turbine OEM's

add an Equivalent Operating hours (EOH) factor for starts and this impacts on the costs under the

LTSA.

EOH costs are based on 2.50 USD/CCGT-MWh or 1.813 EUR/CCGT-MWh at nominal ISO full load

based on discussions with the OEMs. Allowing for the correction from ISO to reference conditions the

equivalent cost is EUR545/GT-EOH. The EOH factor is also increased by the part-load factor since

the EOH measurement is based on operating hours rather than MWh. Note that the LTSA is based on

the gas and steam turbine only rather than maintenance of the whole plant. The starts factor only

impacts on the gas turbine component however. Based on 55 starts/unit and 10 EOH/start, the cost is

SGD 520,037/unit/year.

Additionally, the distillate usage (discussed below) also has an impact on turbine EOH consumption.

Based on 1.5 EOH/hour when operating on distillate, the additional EOH consumption over natural

gas fuel operation is 0.5 EOH/hour. This equates to an impact on maintenance of SGD

38,598/unit/year.

Calculation of the working capital cost and the emergency fuel usage cost below requires an estimate

of the costs of distillate and natural gas. For the purposes of this report prices of 27.00 SGD/GJ and

19.79 SGD/GJ for distillate and gas, respectively are applied.

This distillate cost assumption is based on USD919.33/t (USD123.4/bbl) for this report based on the

average of daily rates for Gasoil (10ppm) from March 2014 through May 2014. A handling and

delivery cost based on the allowance of USD6.12/bbl is added to give a delivered distillate cost of

USD129.52/bbl, or SGD27.00/GJ.

Working capital costs are the annual costs of the financial facilities needed to fund working capital.

This comprises two components:

• Emergency fuel inventory: 90 days (per 2 units), or 8.8PJ. 45 days must be stored on-site and the

remaining 45 days may be stored by the fuel vendor in Singapore provided that it can be securely

delivered to the power station when required. The working capital cost of the extra 45 days will be

somewhere between zero and the working capital cost of the full extra 45 days inventory. Jacobs

SKM are unable to ascertain where in this range the cost that would be charged by the supplier

would be. For the purposes of this report, we have allowed for a midrange estimate of 50%. That

is, an effective working capital cost of 45 + 45/2 days is allowed. This is allowed at the distillate

cost of SGD27.00/GJ and a pre-tax nominal WACC of 8.22% gives a working capital cost of

SGD13.41M/year/2 units; and

• Working capital against the cash cycle (timing of receipts from sales versus payments to suppliers)

based on a net timing difference of 30 days and excluding fuel costs (based on the short settlement

period in the market of 20 days from the time of generation). For two units the working capital

requirement on this basis is SGD4.17M and the working capital cost (using a pre-tax nominal

WACC of 8.22%) is SGD0.34M/year.

Emergency fuel usage is a notional amount of emergency fuel usage for testing, tank turnover etc.

This is calculated as 1% of the annual fuel usage and using a cost based on the extra cost of distillate

over natural gas (SGD27.00/GJ vs SGD19.79/GJ).

Property tax has been estimated based on 10% per year of an assumed Annual Value of 5% of the

land, preparation and buildings/structures cost22. Note is also made of the IRAS circular regarding

property taxes on plant and machinery23. The value of certain fixed plant and machinery items must

be included within the property valuation when calculating property taxes. However an appended list

of exemptions exempts most of the principal plant items of a CCGT plant including turbines,

generators, boilers, transformers, switchgear etc. To allow for the extra value of the portion of the

22 Following http://www.business.gov.sg/EN/Government/TaxesNGST/TypesofTaxes/taxes_property.htm

23 IRAS circular: "TAX GUIDE ON NON-ASSESSABLE PLANT AND MACHINERY COMPONENTS FOR PETROCHEMICAL

AND POWER PLANTS", 16 Nov 2006.

plant that is included, 10% of the cost of the plant is included in the property tax valuation calculation

(except where already included). The total value included for calculation of property tax is thus

SGD272.6M (2 units).

Insurance has been estimated based on 0.5% of the capital cost. This is considered to cover

property, plant and industrial risks but would not cover business interruption insurance or the cost of

hedging against plant outages.

A comparison with the values shown in the previous reviews is shown in Table 22.

Table 22 Fixed annual operating cost allowance comparison, SGD Millions for 2 units

Area 2011-12 review

2013-14 review

2015-15 review (Current review)

Manning 4.20 4.84 5.37

Allowance for head office services 2.52 2.91 3.22

Fixed maintenance and other fixed operations 15.631 16.91 16.11

Starts impact on turbine maintenance 0.935 0.941 1.04

Distillate usage impact on turbine

maintenance

0.0763 0.070 0.078

EMA license fee (fixed) 0.05 0.05778 0.05778

Working capital 13.526 13.599 13.76

Emergency fuel usage 1.497 1.656 2.20

Property Tax 1.037 1.335 1.36

Insurance 5.509 4.697 4.47

Total (for 2 units) per year 44.981 47.019 47.669

4.2 Variable non-fuel cost

It is assumed a Long Term Service Agreement (LTSA) would be sought for the first one to two

overhaul cycles of the gas turbine and steam plant (typically 6 to 12 years). These are typically

structured on a "per operating hour" or "per MWh" basis and hence are largely variable costs.

An assessment of the variable, non-fuel, costs is given in Table 23.

Table 23 Variable non fuel costs

Area SGD/MWh Notes

Gas turbine & steam

turbine

5.136 Based on approximately EUR1.81/MWh of total plant ISO

output, adjusted for reference conditions and part load factor

Steam turbine Incl.

Balance of plant,

chemicals,

consumables

0.55

Town Water 0.178 For a salt water cooled plant the town water costs are

typically small. Based on 0.1t/MWh usage and a cost of

1.781 SGD/t24.

EMC fees 0.276

PSO 0.241 PSO Budget projected 2014/15

EMA license fee

(variable)

0.179 Advised by EMA

Total 6.560

Note the MWh in the above are those of the overall CCGT plant unit, not the individual turbine output.

If the alternative treatment of the LTSA had been adopted (i.e. the LTSA element would be considered

in the fixed costs), the variable operating cost would reduce by approximately SGD5.136/MWh and the

fixed operating cost would increase by approximately SGD22.41M/y (for 2 units). This would not

change the LRMC value calculated.

A comparison with the values shown in the 2011-2012 and 2013-14 reviews is shown in Table 24.

Table 24 Variable operating cost allowance comparison, SGD/MWh

Area 2011-12 review

2013-14 review

2015-16 review Current review

LTSA for Gas turbine 4.64 4.497 5.136

Steam turbine 0.5 0.5 Incl.

Balance of plant, chemicals, consumables 0.5 0.5 0.55

Town Water 0.2 0.178 0.178

EMC fees 0.3343 0.343 0.276

PSO 0.2205 0.221 0.241

EMA license fee (variable) 0.155 0.179 0.179

Total 6.55 6.419 6.560

24 http://www.pub.gov.sg/general/Pages/WaterTariff.aspx for “Non-domestic” NEWater + Waterborne fee

5.1 Build duration

Current expected build duration for this type of plants is 30 months. This is unchanged from the 2013-

2014 review.

5.2 Economic life

The technical life of this type of plant is considered to be approximately 30 years.

The economic life has been assessed at 24 years as discussed in Appendix B (versus 24 years in the

2011-12 review and 22 years in the 2013-14 review).

5.3 Average expected utilisation factor

In the 2011-12 review the plant load factor of the new plant was determined from the average

historical capacity factor of the existing Class F plant for the 12 months leading up to the base month.

For the 2013-14 review this value was 67.3%.

EMA has advised that for consistency with the previous reviews, the actual historic capacity factor for

the previous 12 months should again be applied. This value has been advised by EMA to be 64.4%.

This is lower than for the 2013-2014 review, due to new plant having been commissioned.

5 OTHER PARAMETERS

6.1 Introduction

The LRMC resulting from the inclusion of the parameters are considered in this report along with the

financial parameters that are determined in the financial parameters report or advised by EMA.

For the purposes of comparing the impacts of the changes in technical parameters, a calculation is

included in the LRMC, using assumptions for financial parameters where necessary.

6.2 Summary of technical parameters

Table 25 Summary of recommended technical parameters and previous values

Item Parameter 2011-12 Review

2013-2014 Review

2015-2016 Review

6 Economic capacity of the most economic technology

in operation in Singapore (MW)

381 382.1 386.67MW

net at 32oC

7 Capital cost of the plant identified in item 6 ($US/kW) 1053 997.51 936.79

USD/kW

8 Land, infrastructure and development cost of the

plant identified in item 6 ($Sing million)

152.0M 150.2M SGD

151.27M

11 HHV Heat Rate of the plant identified in item 6

(Btu/kWh)

7010 7103.4 7103.8

btu/kWh

net HHV

12 Build duration of the plant identified in item 6 (years) 2.5 2.5 2.5 years

13 Economic lifetime of the plant identified in item 6

(years)

24 22 24 years

14 Average expected utilisation factor of the plant

identified in item 6, i.e. average generation level as a

percentage of capacity (%)

74.9% 67.3% 64.4%

15 Fixed annual running cost of the plant identified in

item 6 ($Sing)

22.49 23.51 23.83 M

SGD

16 Variable non-fuel cost of the plant identified in item 6

($Sing/MWh)

6.55 6.42 6.56

SGD/MWh

The significant differences from the previous review are considered to be primarily attributable to:

• A reduction in the estimated EPC cost of large CCGT plants in the region; and

• The lower Plant Load Factor (utilisation factor) and consequently the lower part load factor. These

increase the capital cost amortisation costs and the fuel costs (heat rate) respectively.

6 RESULTS – VESTING CONTRACT PARAMETERS

6.3 Calculated LRMC

Table 26 Assumed financial parameters for the LRMC calculation

Parameter Value Notes

WACC 6.82% post-tax, nominal

5.92% pre-tax, real

EMA

CPI 2.17% Average year-on-year core

inflation, Mar 2014, Apr 2014,

May 2014

Gas price $19.79 SGD/GJ EMA

Exchange rates 1.2580 SGD/USD Average bid and ask, daily,

Mar 2014, Apr 2014, May 2014

Table 27 Calculated LRMC for 2015-16

Parameter Value SGD/MWh Notes

Fuel component 148.304

Capital component 28.76 See note below

Fixed opex 10.93

Variable opex 6.560

Total 194.55

Note that in accordance with the Vesting Contract formulae and the treatment in previous years, the

WACC applied in the calculation of the LRMC is the nominal WACC. Comparisons with previous

estimates are shown in Table 28:

Table 28 Comparison of the calculated LRMC with the previous estimate, SGD/MWh

Parameter 2011-12 review 2013-14 review 2015-16 review

(Current review)

WACC 8.43% post-tax,

nominal

6.37% pre-tax, real

6.29% post-tax,

nominal

4.68% pre-tax, real

6.82% post-tax,

nominal

5.92% pre-tax, real

CPI 3.56% 2.77% 2.17%

Gas price $17.22 $22.80 $19.79 SGD/GJ

Exchange rates 1.393 1.2580 1.2580 SGD/USD

Fuel component 127.48 170.87 148.304 SGD/MWh

Capital component 34.80 28.231 28.76 SGD/MWh

Fixed opex 8.99 10.436 10.93 SGD/MWh

Variable opex 6.55 6.419 6.560 SGD/MWh

Total 177.82 215.951 194.55 SGD/MWh


B ECONOMIC LIFE


APPENDICES

Table 29 Excerpt from Vesting Contract Procedures25

No. Parameter Description Method of

Determination

1 Determination Date Date on which the calculations of

the LRMC, which is to apply at

the Application Date, are deemed

to be made

Determined by EMA

2 Base Month Cut-off month for data used in

determination of the LRMC base

parameters.

For the following base

parameters which tend to be

volatile in nature, the data to be

used for estimating each of them

shall be based on averaging over

a three month leading up to and

including the Base Month:

• Exchange rate denominated in

foreign currencies into

Singapore dollars

• Diesel price to calculate cost

of carrying backup fuel

• Risk-free rate

• Debt premium to calculate

cost of debt

• Consumer price index

• Domestic supply price index

• Imported iron and steel index

Determined by EMA

3 Application Date Period for which the LRMC to

apply

Determined by EMA

4 Current Year Year in which the Application

Date falls

Determined by EMA

5 Exchange Rate

($US per $Sing)

The exchange rate is that as

determined in Section 3.8

Determined by EMA (in

consultation with

finance experts)

25 Version 2.0, September 2013



Determination

6 Economic capacity

of the most

economic

technology in

operation in

Singapore (MW)

The size of the most thermally

efficient unit taking into account

the requirements of the

Singapore system, including the

need to provide for contingency

reserve to cover the outage of the

unit and the fuel quantities

available. It is acknowledged that

this value may depend on the

manufacturer. (For CCGT

technology the size of the unit is

expected to be around 370MW)


consultation with the

engineering and power

systems experts)

7 Capital cost of the

plant identified in

item 6 ($US/kW)

Capital cost includes the

purchase and delivery cost of the

plant in a state suitable for

installation in Singapore and all

associated equipment but

excludes switchgears, fuel tanks,

transmission and fuel

connections, land, buildings and

site development included in item

8. Where more than one unit is

expected to be installed that will

share any equipment, the costs

of the shared equipment should

be prorated evenly to each of the

units

Determined b EMA

(and in consultation

with the engineering

and power systems

experts)


Determination

8 Land, infrastructure

and development

cost of the plant

identified in item 6

($Sing million)

Where more than one unit is

expected to be installed that will

share any equipment or facilities,

the costs of the shared

equipment or facilities should be

prorated evenly to each of the

units. These costs should

include all capital, development

and installation costs (excluding

all costs included in item 7 and

financing costs during the build

period). These costs should

include the following specific

items:

• Acquisition costs of sufficient

land to accommodate the

plant defined above in item 6

(alternatively land may be

included as annual rental cost

under Fixed Annual Running

Costs)

• Site development

• Buildings and facilities

• Connectors to gas pipelines

• Switchgear and connections

to transmission

• Emergency fuel facilities

• Project management and

consultancy

Determined by EMA,

(a) In consultation with

the engineering and

power systems experts

in relation to the

following values:

• size of site required

• site development

• buildings and

facilities

• connections to

pipelines

• switchgear

connections to

transmission

• emergency fuel

facilities

• project

management and

consultancy; and

(b) In consultation with

real estate experts in

relation to land value

9a HSFO 180 CST Oil

Price (US$/MT)

The HSFO 180 CST Oil Price is

that as determined in Section 3.7

Determined by EMA

9b Brent Index Price The Brent Index is that as

determined in Section 3.7.2

Determined by EMA

10a Gas Price

($Sing/GJ)

The current most economic

generating technology in

Singapore uses natural gas. This

is the Singapore price for gas

delivered to electricity generating

companies as calculated by the

Authority using existing

Singapore pipeline gas contracts

based on the HSFO price or any

other method as determined by

the Authority and announced to

the gas industry.

Determined by EMA


Determination

10b LNG Price

($Sing/GJ)

This is the Singapore regasified

LNG price as determined by the

Authority. The LNG price is used

in place of 10a for the LNG

Vesting Quantities under the LNG

Vesting Scheme.

The LNG Price includes:

• the LNG hydrocarbon charge

• any fees or charges imposed

by the Authority on the

imported gas

• the LNG terminal tariff

• the average gas pipeline

transportation tariff applicable

to regasified LNG

• the LNG Aggregator’s margin

• the cost of Lost and

Unaccounted For Gas (LUFG)

Determined by EMA

11 HHV Heat Rate of

the plant identified

in item 6 (Btu/kWh)

The high heat value heat rate of

the plant specified under item 6

that this expected to actually be

achieved, taking into account any

improvement or degradation in

efficiency from installation in

Singapore and other reasonable

factors




systems experts)

12 Build duration of


in item 6 (years)

The time from the

commencement of the major cost

of development and installation

being incurred up to the time of

the plant commissioning. This

parameter is used to calculate

the financing cost over the

duration of the building period

and assumes that the

development costs are incurred

evenly across this period. The

build duration should be specified

to reflect this use and meaning as

opposed to the actual time from

the commencement of site

development to the time of plant

commissioning.




systems experts)


Determination

13 Economic lifetime

of the plant


(years)

The expected time from

commissioning to

decommissioning of the plant.

This number is used to amortise

the capital cost of the plant, and

of installation and development.




systems experts)

14 Average expected

utilisation factor of


in item 6, i.e.

average generation

level as a

percentage of

capacity (%)

The utilisation factor is the

expected annual proportion of

plant capacity that will be used

for supplying energy for sale. It

should exclude station usage,

expected maintenance and

forced outages and the expected

time spent providing reserve

capacity. The determination of

the factor should assume that the

plant is efficiently base-loaded




systems experts)

15 Fixed annual

running cost of the

plant identified in

item 6 ($Sing)

These costs are the fixed

operating and overhead costs

that are incurred in having the

plant available for supplying

energy and reserves but which

are not dependent on the quantity

of energy supplied. It is

acknowledged that some costs

are not easily classified as fixed

or variable. The costs expected

to be included in this parameter

are:

• Operating labour cost – it is

expected that the plant will be

running for three shifts per day

and seven days per week so

all operating labour cost is

likely to be a fixed annual cost

• Direct overhaul and

maintenance cost, with any

semi-variable costs treated as

annual fixed costs

• Generating license

• Insurance

• Property tax

• Costs of emergency fuel

• Other charges

• Other overhead costs

(a) Determined by

EMA, in consultation

with engineering and

power systems experts

in relation to the

following values:

• Operating labour

• Direct overhaul and

maintenance cost

• Costs of emergency

fuel

• Other overhead

costs; and

(b) Determined solely

by EMA

• Generating license

• Insurance

• Property tax

• Other charges


Determination

16 Variable non-fuel

cost of the plant


($Sing/MWh)

Any costs, other than fuel costs,

that vary with the level of energy

output for a base-load plant and

are not covered by item 15




systems experts

17 Proportion of debt

by assets

The proportion of debt to total

assets at market value. It is an

estimate of the industry standard

ratio for private sector generators

in an economic environment

similar to Singapore. The ratio is

used to calculate the weighted

average cost of capital (“WACC”)



finance experts)

18 Risk free Rate (%) The risk-free rate plus a premium

as determined by the Authority.

The total cost of debt will

comprise the base lending rate,

the loan margin and upfront and

other fees



finance experts)

19 Cost of Debt (%) Risk-free rate plus a premium as

determined by the Authority. The

total cost of debt will comprise

the base lending rate, the loan

margin and upfront and other

fees



finance experts)

20 Market Risk

Premium (%)

The market risk premium

represents the additional return

over investing in risk-free

securities that an investor will

demand for investing in electricity

generators in Singapore, as

determined by the Authority



finance experts)

21 Beta Parameter of scaling the market

risk premium for calculating the

cost of equity as determined by

the Authority. Beta is a measure

of the expected volatility of the

returns on a project relative to the

returns on the market, that is, the

systematic risk of the project



finance experts)


Determination

22 Tax rate (%) Corporate tax rate applicable to

generating companies in

Singapore at the base date. This

rate should include any

applicable tax rebates or tax

incentives available to generating

companies, and be consistent

with the gearing and interest

rates defined in 17 &18

Determined by EMA

23 Cost of equity (%) The return of equity for the

business as calculated from the

previous data. It is calculated as

item 18+ (item 20) (item 21) +

item 22

Calculated by EMA (in


finance experts)

The economic life of the new entrant is dictated by the rate of development of the heat rate of newer

plants and real reductions in capex of newer plants.

Based on the parameters in Gas Turbine World Handbooks of 1994 and 2012, and applying “E” class

CCGT’s in 1994 and the latest “F/H” class units in the 2012 Handbook, the average improvement in

heat rate per year was assessed as -0.0077 GJ/MWh/y. The real rate of reduction in specific capital

cost was assessed as 2.29% per year.

Applying these rates of change to the new entrant parameters it is calculated that the LRMC of a

newer unit would become lower than the SRMC of an incumbent after 24.5 years. Thus the economic

life of the new entrant plant is assessed to be 24 years.

B ECONOMIC LIFE

Performance analysis of new entrant "F" class CCGT units has been undertaken using the GTPro and

GTMaster software suite Version 24 (May 2014 update). Analyses have been made based on

optimisation at the site average ambient and cooling water conditions. Representative performance

parameters as calculated are shown in the following figures:


Figure 13 Performance analysis - Alstom "F" class CCGT, clean-as-new, At Reference conditions

GT MASTER 24.0 Sinclair Knight Merz

464 06-25-2014 19:09:46 fi le=C:\Users\RZauner\Documents\SKM Projects\EMA Vesting contracts 2014\GTPro\Thermoflow24\SIEMENS 4000F CCGT SINGCONDS 2014.GTM

Net Power 381427 kWLHV Net Heat Rate 6284 kJ/kWhLHV Net Efficiency 57.29 %

p[bar], T[C], M[t/h], Steam Properties: IFC-67

1X Siemens SGT5-4000F

(Curve Fit OEM Data Model #397)

ST

389178 kW

GT 261770 kW

1.01 p 30 T

85 %RH

2230.7 m

1 p

30 T 2230.7 m

Natural gas 51.79 m

185 T25TLHV= 665764 kWth

2282.4 m

1.04 p 596 T 2282.4 M

72.69 %N2 12.12 %O2 3.789 %CO2 10.52 %H2O 0.8738 %Ar

595 T 2282.4 M

2.453 m^3/kg1555.5 m^3/s

595 585 563 552 522 460 344 343 322 316 313 281 249 197 197 152 152

98 T 2282.4 M

1.082 m^3/kg686.2 m^3/s

131223 kW

0.41 M

FW

0.0828 p 42 T 348 M 0.9388 x

42 T

3.8 p

132 T

348.8 M

LTE

43 T 348.8 M

132 T 3.8 p 142 T

18.07 M

52.18 M

3.8 p

142 T

52.18 M

LPB

8.239 M

3.62 p

290 T

43.94 M

LPS

43.94 M

3.382 p 288 T

322.9 M

32.21 p 143 T

31.27 p

233 T

322.9 M

IPE2

31.27 p

236 T

44.67 M

IPB

30.91 p

292 T

44.67 M

IPS1

30.66 p

320 T

44.67 M

IPS2

134.1 p 237 T

132.1 p

296 T

278.2 M

HPE2

130.2 p

328 T

278.2 M

HPE3

18.07 M

130.2 p

331 T

260.2 M

HPB1

128 p

488 T

260.2 M

HPS0

127.1 p

528 T

260.2 M

HPS1

125.8 p

567 T

260.2 M

HPS3

124 p 566 T 260.2 M

125.8 p 567 T

250.5 M

31.88 p 368 T

29.96 p

479 T

295.2 M

RH1

28.66 p

567 T

295.2 M

RH3

295.2 M

27.6 p 566 T

Figure 14 Performance analysis - GE "F" class CCGT, clean-as-new, At Reference conditions


464 06-25-2014 18:26:59 file=C:\Users\RZauner\Documents\SKM Projects\EMA Vesting contracts 2014\GTPro\Thermoflow24\GE 9F 5 series CCGT SINGCONDS 2014.GTM



1X GE 9F 5-series

(Physical Model #475)

ST

408206 kW

GT 262778 kW

1.01 p

30 T

85 %RH

2140.4 m

1 p

30 T

2140.4 m

Natural gas 54.09 m

185 T25TLHV= 695431 kWth

16.84 p 422 T

16 p 1411 T

2194.5 m

1.04 p 657 T 2194.5 M

72.46 %N2 11.44 %O2 4.109 %CO2 11.13 %H2O 0.8709 %Ar

656 T 2194.5 M

2.631 m^3/kg1603.5 m^3/s

656 643 618 605 571 491 344 343 317 313 311 270 249 188 188 152 152

91 T 2194.5 M

1.064 m^3/kg648.4 m^3/s

149321 kW

0.49 M

FW

0.0828 p 42 T 378.7 M 0.9386 x

42 T

3.8 p

132 T

379.5 M

LTE

43 T 379.5 M

132 T 3.8 p 142 T

18.88 M

39.87 M

3.8 p

142 T

39.87 M

LPB

8.913 M

3.62 p

290 T

30.95 M

LPS

30.95 M 3.382 p 289 T

367.4 M

32.21 p 143 T

31.27 p

233 T

367.4 M

IPE2

31.27 p

236 T

27.99 M

IPB

30.99 p

292 T

27.99 M

IPS1

30.65 p

320 T

27.99 M

IPS2

134.1 p 237 T

132 p

296 T

339.4 M

HPE2

130.2 p

328 T

339.4 M

HPE3

18.88 M

130.2 p

331 T

320.5 M

HPB1

127.8 p

488 T

320.5 M

HPS0

126.9 p

528 T

320.5 M

HPS1

125.8 p

567 T

320.5 M

HPS3

124 p 566 T 320.5 M

125.8 p 567 T

309.8 M 31.87 p 367 T

30.08 p

479 T

337.8 M

RH1

28.66 p

567 T

337.8 M

RH3

337.8 M 27.6 p 566 T

Figure 15 Performance analysis - Mitsubishi "F" class CCGT, clean-as-new, At Reference conditions


464 06-25-2014 18:19:44 fi le=C:\Users\RZauner\Documents\SKM Projects\EMA Vesting contracts 2014\GTPro\Thermoflow24\M701F4 CCGT SINGCONDS 2014.GTM


p[bar], T [C], M[t/h], Steam Properties: IFC-67

1X Mitsubishi 701 F4

(Physical Model #463)

ST

444618 kW

GT 300869 kW

1.01 p 30 T

85 %RH

2413.9 m

1 p 30 T

2413.9 m

Natural gas 59.27 m

185 T25TLHV= 762016 kWth

17.15 p 427 T

16.46 p 1395 T

2473.2 m

1.04 p 608 T 2473.2 M

72.54 %N2 11.68 %O2 3.997 %CO2 10.92 %H2O 0.8719 %Ar

607 T 2473.2 M

2.492 m^3/kg1712 m^3/s

607 597 574 563 532 466 344 343 321 316 313 279 249 195 195 152 152

97 T 2473.2 M

1.079 m^3/kg741.4 m^3/s

147849 kW

0.47 M

FW

0.0828 p 42 T 387.8 M 0.9389 x

42 T

3.8 p

132 T 388.5 M

LTE

43 T 388.5 M

132 T 3.8 p 142 T

20.68 M

54.12 M

3.8 p

142 T 54.12 M

LPB

9.218 M

3.619 p

290 T 44.91 M

LPS

44.91 M

3.382 p 289 T

364.3 M

32.22 p 143 T

31.29 p

233 T 364.3 M

IPE2

31.29 p

236 T 44.84 M

IPB

30.94 p

292 T 44.84 M

IPS1

30.67 p

320 T 44.84 M

IPS2

134.1 p 237 T

132.2 p

296 T 319.5 M

HPE2

130.2 p

328 T 319.5 M

HPE3

20.68 M

130.2 p

331 T 298.8 M

HPB1

127.8 p

488 T 298.8 M

HPS0

127.2 p

528 T 298.8 M

HPS1

125.8 p

567 T 298.8 M

HPS3

124 p 566 T 298.8 M

125.8 p 567 T

288.4 M

31.88 p 368 T

29.77 p

479 T 333.3 M

RH1

28.66 p

567 T 333.3 M

RH3

333.3 M

27.6 p 566 T

Figure 16 Performance analysis - Alstom "F" class CCGT, clean-as-new, At Reference conditions


464 06-25-2014 18:13:06 file=C:\Users\RZauner\Documents\SKM Projects\EMA Vesting contracts 2014\GTPro\Thermoflow24\ALSTOM GT26 CCGT SINGCONDS 2014.GTM



1X ALSTOM GT26 (2006)

(Curve Fit OEM Data Model #460)

ST

414348 kW

GT 263275 kW

1.01 p 30 T

85 %RH 2137.5 m

1 p

30 T 2137.5 m

Natural gas 54.68 m

185 T25TLHV= 702947 kWth

2192.2 m

1.04 p 632 T 2192.2 M

72.43 %N2 11.33 %O2 4.156 %CO2 11.21 %H2O 0.8705 %Ar

631 T 2192.2 M

2.56 m^3/kg1558.9 m^3/s

631 618 591 577 540 471 344 343 321 318 315 282 249 181 181 152 152

89 T 2192.2 M

1.058 m^3/kg644.4 m^3/s

155055 kW

0.5 M

FW

0.0828 p 42 T 390.6 M 0.9384 x

42 T

3.8 p 132 T

391.5 M

LTE

43 T 391.5 M

132 T 3.8 p 142 T

35.92 M

32.74 M

3.8 p 142 T

32.74 M

LPB

10.46 M

3.619 p 290 T

22.27 M

LPS

22.27 M

3.382 p 288 T

405.1 M

32.23 p 143 T

31.29 p 233 T

405.1 M

IPE2

35.92 M

31.29 p 236 T

44.25 M

IPB

30.92 p 292 T

44.25 M

IPS1

30.67 p 320 T

44.25 M

IPS2

134.1 p 237 T

48.54 M

132.3 p 296 T

276.4 M

HPE2

130.2 p 328 T

276.4 M

HPE3

130.2 p 331 T

276.4 M

HPB1

127.8 p 488 T

276.4 M

HPS0

48.54 M

127 p 528 T

324.9 M

HPS1

125.8 p 567 T

324.9 M

HPS3

124 p 566 T 324.9 M

125.8 p 567 T

314.1 M

31.88 p 367 T

29.77 p 479 T

358.4 M

RH1

28.66 p 567 T

358.4 M

RH3

358.4 M

27.6 p 566 T