ENERGY MARKET AUTHORITY Review of the Vesting Contract Technical Parameters for the period 1 January 2015 to 31 December 2016
22 September 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:
1
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
2
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
3
CONTENTS
DISCLAIMER 1
EXECUTIVE SUMMARY 2
LRMC technical parameters 2
1 INTRODUCTION 7
1.1 Financial parameters 7
1.2 Disclaimer 9
2 PERFORMANCE PARAMETERS 10
2.1 Existing generators 10
2.2 Generating technology 11
2.3 Capacity per generating unit 13
2.4 Impact of gas compression and resulting net capacity 17
2.5 Heat Rate 19
3 CAPITAL COST 24
3.1 Method 24
3.2 Initial capital cost 27
3.3 Through-life capital costs 29
3.4 Land and Site Preparation Cost 29
3.5 Connection Cost 30
3.6 Owner's costs after financial closure 31
3.7 Owner's costs prior to Financial Closure 32
4 OPERATING COSTS 34
4.1 Fixed annual running cost 34
4.2 Variable non-fuel cost 37
5 OTHER PARAMETERS 39
5.1 Build duration 39
5.2 Economic life 39
5.3 Average expected utilisation factor 39
6 RESULTS – VESTING CONTRACT PARAMETERS 40
6.1 Introduction 40
6.2 Summary of technical parameters 40
6.3 Calculated LRMC 41
APPENDICES 43
4
A PRESCRIBED PROCEDURES 44
B ECONOMIC LIFE 51
C THERMODYNAMIC ANALYSIS 52
5
FIGURES AND TABLES
FIGURES
Figure 1 Singapore CPI data 8
Figure 2 Foreign exchange rate trends 9
Figure 3. Form of CCGT recoverable and non-recoverable degradation 16
Figure 4 Effect of ambient temperature on power output 17
Figure 5 Gas compressor power requirements for relevant gas turbines 18
Figure 6 Gas pressures in TUAS area, 2010 to 2014 18
Figure 7 Impact of ambient temperature on heat rate 21
Figure 8 Variation of heat rate at part load 22
Figure 9. Capex estimation method 25
Figure 10 Trends in Singapore local construction cost parameters, 2010 = 100 27
Figure 11 Assumed electrical connection configuration (items per Table 18) 31
Figure 12 Labour cost index 35
Figure 13 Performance analysis - Alstom "F" class CCGT, clean-as-new, At Reference
conditions and at 32oC 53
Figure 14 Performance analysis - GE "F" class CCGT, clean-as-new, At Reference conditions
and at 32oC 54
Figure 15 Performance analysis - Mitsubishi "F" class CCGT, clean-as-new, At Reference
conditions and at 32oC 55
Figure 16 Performance analysis - Siemens "F" class CCGT, clean-as-new, At Reference
conditions and at 32oC 56
TABLES
Table 1 Summary of recommended technical parameters 2
Table 2 Finance parameters applied 7
Table 3 Registered capacity, large CCGT units 10
Table 4 Existing Singapore station parameters (large F class CCGT units) 11
Table 5 Generation capacity of new entrant CCGT units (clean-as-new at Reference Conditions,
excluding gas compression impacts) 14
Table 6 Auxiliary loads incorporated within GTPro models, kW 14
Table 7 Variation in net power output with ambient temperature (relative to Reference
Conditions) 16
Table 8 Gas pressure trends, kPag 19
Table 9 Generation capacity of new entrant CCGT units 19
6
Table 10 Heat rate of new entrant CCGT units (clean-as-new at Reference Conditions excluding
gas compression) 20
Table 11 Variation in net heat rate with ambient temperature (relative to Reference Conditions) 20
Table 12 Variation of heat rate with part load (%) 21
Table 13 Heat rate of new entrant CCGT units 23
Table 14 Gas Turbine World Handbook budget plant prices for CCGT units, USD/kWISO 26
Table 15 Local construction cost parameters (nominal) for Singapore 26
Table 16 EPC capital cost summary (per unit) for 2015-16, with comparison against earlier
reviews 28
Table 17 Through-life capital expenditure (per unit) 29
Table 18 Electrical connection costs (2 units) 30
Table 19 Owner's costs allowances (after financial closure) 32
Table 20 Owner's costs allowances prior to Financial Closure 33
Table 21 Fixed annual operating cost allowance 34
Table 22 Fixed annual operating cost allowance comparison, SGD Millions for 2 units 37
Table 23 Variable non fuel costs 38
Table 24 Variable operating cost allowance comparison, SGD/MWh 38
Table 25 Summary of recommended technical parameters and previous values 40
Table 26 Assumed financial parameters for the LRMC calculation 41
Table 27 Calculated LRMC for 2015-16 41
Table 28 Comparison of the calculated LRMC with the previous estimate, SGD/MWh 42
Table 29 Excerpt from Vesting Contract Procedures 44
7
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
Debt premium 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.
1 INTRODUCTION
8
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)
9
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
10
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
SNK CCP 2 (Senoko) 425 1996 EMA/GE/012
SNK CCP 3 (Senoko) 365 2002 EMA/GE/012
SNK CCP 4 (Senoko) 365 2004 EMA/GE/012
SNK CCP 5 (Senoko) 365 2004 EMA/GE/012
SNK CCP 6 (Senoko) 431 2012 EMA/GE/012
SNK CCP 7 (Senoko) 431 2012 EMA/GE/012
SembCorp Cogen SKACCP1 392.5 2001 EMA/GE/004
SembCorp Cogen SKACCP2 392.5 2001 EMA/GE/004
SembCorp Cogen SKACCP3 403.8 2014 EMA/GE/004
TUAS Stage 2 CCP1 367.5 2001 EMA/GE/009
TUAS Stage 2 CCP2 367.5 2002 EMA/GE/009
TUAS Stage 2 CCP3 367.5 2005 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
Power Seraya CCP2 364 2002 EMA/GE/016
Power Seraya CCP3 370 2010 EMA/GE/016
2 http://www.ema.gov.sg/page/115/id:129/
2 PERFORMANCE PARAMETERS
11
Large CCGT units Reg. Cap,
MW
Date Licence
Power Seraya CCP4 370 2010 EMA/GE/016
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
12
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
13
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
29 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.
14
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
15
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 0).
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
16
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
17
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
18
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
19
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.
20
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%
21
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
22
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 0, 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
23
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
24
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
25
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
26
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
27
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
28
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
29
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
30
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
31
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
32
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.
33
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.
34
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
35
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
)
36
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.
37
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.
38
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
39
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
40
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
41
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
Debt premium advised by 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:
42
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 $19.79 SGD/GJ
Exchange rates 1.393 1.2580 1.2580 SGD/USD
Fuel component 127.48 170.87 148.304 SGD/MWh
Capital component 34.80 28.231 28.76 SGD/MWh
Fixed opex 8.99 10.436 10.93 SGD/MWh
Variable opex 6.55 6.419 6.560 SGD/MWh
Total 177.82 215.951 194.55 SGD/MWh
43
A PRESCRIBED PROCEDURES 44
B ECONOMIC LIFE 51
C THERMODYNAMIC ANALYSIS 52
APPENDICES
44
Table 29 Excerpt from Vesting Contract Procedures25
No. Parameter Description Method of
Determination
1 Determination Date Date on which the calculations of
the LRMC, which is to apply at
the Application Date, are deemed
to be made
Determined by EMA
2 Base Month Cut-off month for data used in
determination of the LRMC base
parameters.
For the following base
parameters which tend to be
volatile in nature, the data to be
used for estimating each of them
shall be based on averaging over
a three month leading up to and
including the Base Month:
• Exchange rate denominated in
foreign currencies into
Singapore dollars
• Diesel price to calculate cost
of carrying backup fuel
• Risk-free rate
• Debt premium to calculate
cost of debt
• Consumer price index
• Domestic supply price index
• Imported iron and steel index
Determined by EMA
3 Application Date Period for which the LRMC to
apply
Determined by EMA
4 Current Year Year in which the Application
Date falls
Determined by EMA
5 Exchange Rate
($US per $Sing)
The exchange rate is that as
determined in Section 3.8
Determined by EMA (in
consultation with
finance experts)
25 Version 2.0, September 2013
A PRESCRIBED PROCEDURES
45
No. Parameter Description Method of
Determination
6 Economic capacity
of the most
economic
technology in
operation in
Singapore (MW)
The size of the most thermally
efficient unit taking into account
the requirements of the
Singapore system, including the
need to provide for contingency
reserve to cover the outage of the
unit and the fuel quantities
available. It is acknowledged that
this value may depend on the
manufacturer. (For CCGT
technology the size of the unit is
expected to be around 370MW)
Determined by EMA (in
consultation with the
engineering and power
systems experts)
7 Capital cost of the
plant identified in
item 6 ($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)
46
No. Parameter Description Method of
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
($Sing/GJ)
The current most economic
generating technology in
Singapore uses natural gas. This
is the Singapore price for gas
delivered to electricity generating
companies as calculated by the
Authority using existing
Singapore pipeline gas contracts
based on the HSFO price or any
other method as determined by
the Authority and announced to
the gas industry.
Determined by EMA
47
No. Parameter Description Method of
Determination
10b LNG Price
($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
Determined by EMA (in
consultation with the
engineering and power
systems experts)
12 Build duration of
the plant identified
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.
Determined by EMA (in
consultation with the
engineering and power
systems experts)
48
No. Parameter Description Method of
Determination
13 Economic lifetime
of the plant
identified in item 6
(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.
Determined by EMA (in
consultation with the
engineering and power
systems experts)
14 Average expected
utilisation factor of
the plant identified
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
Determined by EMA (in
consultation with the
engineering and power
systems experts)
15 Fixed annual
running cost of the
plant identified in
item 6 ($Sing)
These costs are the fixed
operating and overhead costs
that are incurred in having the
plant available for supplying
energy and reserves but which
are not dependent on the quantity
of energy supplied. It is
acknowledged that some costs
are not easily classified as fixed
or variable. The costs expected
to be included in this parameter
are:
• Operating labour cost – it is
expected that the plant will be
running for three shifts per day
and seven days per week so
all operating labour cost is
likely to be a fixed annual cost
• Direct overhaul and
maintenance cost, with any
semi-variable costs treated as
annual fixed costs
• Generating license
• Insurance
• Property tax
• Costs of emergency fuel
• Other charges
• Other overhead costs
(a) Determined by
EMA, in consultation
with engineering and
power systems experts
in relation to the
following values:
• Operating labour
• Direct overhaul and
maintenance cost
• Costs of emergency
fuel
• Other overhead
costs; and
(b) Determined solely
by EMA
• Generating license
• Insurance
• Property tax
• Other charges
49
No. Parameter Description Method of
Determination
16 Variable non-fuel
cost of the plant
identified in item 6
($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
Determined by EMA (in
consultation with the
engineering and power
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”)
Determined by EMA (in
consultation with the
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
Determined by EMA (in
consultation with the
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
Determined by EMA (in
consultation with the
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
Determined by EMA (in
consultation with the
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
Determined by EMA (in
consultation with the
finance experts)
50
No. Parameter Description Method of
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
consultation with the
finance experts)
51
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
52
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:
C THERMODYNAMIC ANALYSIS
53
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
54
Figure 14 Performance analysis - GE "F" class CCGT, clean-as-new, At Reference conditions
GT MASTER 24.0 Sinclair Knight Merz
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
Net Power 399634 kWLHV Net Heat Rate 6265 kJ/kWhLHV Net Efficiency 57.47 %
p[bar], T[C], M[t/h], Steam Properties: IFC-67
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
55
Figure 15 Performance analysis - Mitsubishi "F" class CCGT, clean-as-new, At Reference conditions
GT MASTER 24.0 Sinclair Knight Merz
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
Net Power 435729 kWLHV Net Heat Rate 6296 kJ/kWhLHV Net Efficiency 57.18 %
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
56
Figure 16 Performance analysis - Alstom "F" class CCGT, clean-as-new, At Reference conditions
GT MASTER 24.0 Sinclair Knight Merz
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
Net Power 405762 kWLHV Net Heat Rate 6237 kJ/kWhLHV Net Efficiency 57.72 %
p[bar], T[C], M[t/h], Steam Properties: IFC-67
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
57