4fc89288c1399 skm draft-report_-_review_of_lrmc_parameters_for_2013-14

Review of the vesting contract
parameters for 2013 and 2014 –
Draft report

LONG RUN MARGINAL COST (LRMC)
PARAMETERS
Ver. 6 (Draft)
31 May 2012

Review of vesting contract parameters
for 2013 and 2014 – Draft report

LONG RUN MARGINAL COST (LRMC) PARAMETERS
Ver. 6 (Draft)
31 May 2012

SKM (Singapore) Pte. Ltd.
UEN 198 905 658K
A subsidiary of Sinclair Knight Merz
80 Marine Parade Road
#18-01/04 Parkway Parade,
Singapore 449269
Tel: +65 6345 3055
Fax: +65 6344 8441
Web: www.globalskm.com

COPYRIGHT: The concepts and information contained in this document are the property of SKM
(Singapore) Pte. Ltd., a subsidiary of Sinclair Knight Merz. Use or copying of this document in whole
or in part without the written permission of SKM (Singapore) Pte. Ltd., a subsidiary of Sinclair Knight
Merz constitutes an infringement of copyright.
LIMITATION: This report has been prepared on behalf of and for the exclusive use of SKM
(Singapore) Pte. Ltd., a subsidiary of Sinclair Knight Merz’s Client, and is subject to and issued in
connection with the provisions of the agreement between SKM (Singapore) Pte. Ltd., a subsidiary of
Sinclair Knight Merz and its Client. SKM (Singapore) Pte. Ltd., a subsidiary of Sinclair Knight Merz
accepts no liability or responsibility whatsoever for or in respect of any use of or reliance upon this
report by any third party.

The SKM logo trade mark is a registered trade mark of Sinclair Knight Merz Pty Ltd.

Long Run Marginal Cost (LRMC) parameters, 2013-2014 – Draft report

Contents
1. Executive summary 1
1.1. Introduction 1
1.2. LRMC technical parameters 1
1.3. Review of scale factor indices 1
2. Introduction 3
2.1. General 3
2.2. Financial parameters 3
2.3. Disclaimer 6
3. Performance parameters 7
3.1. Introduction 7
3.2. Generating technology 8
3.3. Capacity per generating unit 11
3.4. Impact of Gas Compression and Resulting Net Capacity 14
3.5. Heat Rate 17
4. Capital cost 21
4.1. Introduction 21
4.2. Method 21
4.3. Initial capital cost 24
4.4. Through-life capital costs 26
4.5. Land and Site Preparation Cost 26
4.6. Connection Cost 27
4.7. Owner's costs after financial closure 28
4.8. Owner's costs prior to Financial Closure 30
5. Operating costs 31
5.1. Fixed annual running cost 31
5.2. Variable non-fuel cost 35
6. Other parameters 37
6.1. Build duration 37
6.2. Economic life 37
6.3. Average expected utilisation factor 37
7. Results – vesting contract parameters 38
7.2. Summary of technical parameters 38
7.3. Calculated LRMC 39

PAGE i


8. Review of Scale Factor Indices 40
8.2. SKM Consideration 41
8.3. Other alternatives 43
Appendix A Prescribed procedures 46
Appendix B Market modelling 51
Appendix C Technical performance data 53
Thermodynamic analysis 53

PAGE ii


1. Executive summary
1.1. Introduction

Sinclair Knight Merz (SKM) has been engaged by the Energy Market Authority (EMA) to provide
recommended values for the technical parameters of the Vesting Contracts for electricity
generation in Singapore for the period 2013 and 2014, and to review the Scale Indices method
within the Vesting Contract Procedures.

1.2. LRMC technical parameters

The following values are recommended by SKM for use in the Vesting Contract parameters for
2013-14.

Table 1 Summary of recommended technical parameters
Item Parameter 2013-14 Value
6 Economic capacity of the most economic technology in 383.47 MW net at 32oC
operation in Singapore (MW)
7 Capital cost of the plant identified in item 6 ($US/kW) 1004.21 USD/kW
8 Land, infrastructure and development cost of the plant SGD 147.81M
identified in item 6 ($Sing million)
11 HHV Heat Rate of the plant identified in item 6 (Btu/kWh) 6886 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) 20 years
14 Average expected utilisation factor of the plant identified 72.8%
in item 6, i.e. average generation level as a percentage of
capacity (%)
15 Fixed annual running cost of the plant identified in item 6 18.297M SGD
($Sing)
16 Variable non-fuel cost of the plant identified in item 6 5.21 SGD/MWh
($Sing/Mwh)

1.3. Review of scale factor indices

The formulation of the index forecast for quarter D+1 using the trend from quarter D-2 to D does
potentially introduce volatility to the calculation of the cost indices. Where the index growth of
two consecutive quarters exhibit either high positive or high negative numbers, the forecast for
D+1 quarter will exacerbate the trend. Also the use of quarterly data that constantly moves while
the base quarter is fixed means that the trend since the base quarter is not necessarily reflected.
Using a longer period between quarters however is likely to reduce volatility. Fixing the index at
the base quarter plus using the trend going forward from the base quarter is likely to both reduce
volatility as well as reflect the trend in cost movements since the base quarter.


PAGE 1


Alternatives to reduce volatility that the EMA may be considered include:

• removing indexation or reducing the frequency of the adjustments (eg. Annual adjustments
rather than quarterly adjustments)
• using a less volatile index (eg the MAS core inflation index) instead of the CPI/DSPI
• undertaking an annual review of capital cost
Given the dissatisfaction expressed by various parties regarding the volatility of vesting prices due
to the indexation process, SKM recommends that changes be made to the method of determining
the LRMC Scale Factor Indices within the two year price period. We recommend that for the
overhead cost component, quarterly indexation be removed and replaced with an annual adjustment
to reflect forecast inflation over the year.

For capital costs, if the EMA is of the opinion that the cost of undertaking an annual review is
justified by the likely savings due to the use of an unsuitable index, SKM recommends that an
annual review be made of the capital cost components.

PAGE 2


2. Introduction
2.1. General

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 2013 through to 31 December
2014.

EMA has engaged Sinclair Knight Merz (SKM) to:

• Conduct a comprehensive review and recommend the value of each vesting contract
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 2013 to 31
December 2014; and
• Review and recommend improvements to the method for calculating the LRMC Scale
Factor Indices (set out in Section 3.8 of the Vesting Contract Procedures), taking into
consideration the objective to reduce the quarterly volatility of the vesting price.
This review of the vesting contract parameters follows the method adopted by SKM (as sub-
consultant to PA Consulting) in the review of parameters for the period 1 January 2011 to 31
December 2012 (the “2011-12” review) 1 .

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 fifth of these two
yearly reviews is the subject of this project, covering the period 1 January 2013 to 31 December
2014.

2.2. Financial parameters

Financial parameters are to be provided by EMA and will be updated prior to the final report.

For the purposes of the Draft report, financial parameters have been provided by EMA and recent
market observations by SKM.

1
PA Consulting Group “Review of the Parameters for Setting the Vesting Contract Price for 2011 and 2012 – Final Report”,
27 September 2010.

PAGE 3


Table 2 Finance parameters applied (pending EMA recalculation)
Parameter Value Notes
WACC 5.26% post-tax, nominal Nominal rate advised by EMA
3.20% pre-tax, real
CPI 3.03% Average year-on-year core
inflation, Dec 2011, Jan 2012,
Feb 2012. Refer Figure 1.
Gas price $22.100 SGD/GJ (PNG) Advised by EMA. For the
PNG price, EMA have used the
average quarterly forward
HSFO prices and USD/SGD
exchange rates for the period
Dec 11 to Feb 12
Exchange rates 1.2764 SGD/USD Average bid and ask, daily,
1.6716 SGD/EUR 1/12/2011 to 29/2/2012. Refer
Figure 2 and Figure 3.

Figure 1 Singapore CPI data 2
6.0

5.0

4.0
Year on year %

3.0

2.0

CPI (Y‐o‐Y)

1.0    MAS core CPI (Y‐o‐Y)

‐

2
Monthly data Department of Statistics, Singapore, http://www.singstat.gov.sg/news/news/cpimar2012.pdf and earlier
editions

PAGE 4


Figure 2 Fx data Dec 2011 to Feb 2012
2.0

1.8

1.6

1.4

1.2
fx reate

1.0
SGD/USD

0.8
SGD/EUR

0.6

0.4

0.2

0.0
1/12/2011 1/01/2012 1/02/2012 1/03/2012

PAGE 5


Figure 3 Foreign exchange rate trends 3
2.50

2.00

1.50
fx rates, daily

1.00
USD/SGD
EUR/SGD

0.50

0.00
Jan 2007 Jul 2007 Jan 2008 Jul 2008 Jan 2009 Jul 2009 Jan 2010 Jul 2010 Jan 2011 Jul 2011 Jan 2012

2.3. Disclaimer

This report has been prepared for the benefit of EMA for the purposes of setting the vesting
contract price for the 2013 to 2014 period. This report may not be relied upon by any other entity
and may not be relied upon for any other purpose.

3
Data based on Reserve Bank of Australia implied cross rates

PAGE 6


3. Performance parameters
3.1. Introduction

Parameters for the existing generation fleet in Singapore 4 are shown in Table 3.

Table 3 Registered capacity, large CCGT units
Large CCGT units Reg Cap, Date Licence
MW
Tuaspring Pte Ltd HFLXCC‐1 411 2H 2014 EMA/GE/015
SNK CCP 1 (Senoko) 425 1996 EMA/GE/012
SNK CCP 6 (Senoko) 431 2H 2012 EMA/GE/012
SNK CCP 7 (Senoko) 431 2H 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 400 1Q 2014 EMA/GE/004
SembCorp Cogen SKACCP4 500 TBA EMA/GE/004
TUAS Stage 2 CCP1 367.5 2001 EMA/GE/009
TUACCP4 367.5 2005 EMA/GE/009
Power Seraya CCP1 368 2002 EMA/GE/016
Keppel Merlimau Cogen GRF 3 420 1Q 2013 EMA/GE/006
Keppel Merlimau Cogen GRF 4 420 3Q 2013 EMA/GE/006
GMR Unit 1 400 Nov‐13 EMA/GE/005
GMR Unit 2 400 Jan‐14 EMA/GE/005

4
http://www.ema.gov.sg/page/115/id:129/

PAGE 7


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

3.2. Generating technology

The parameters for the existing relevant power stations in Singapore, extracted from the 2010
report for 2011-12, and updated with the selected gas turbines for plants recently committed, are
given in Table 4:

Table 4 Existing Singapore station parameters (large CCGT units) 5
Power station Train Number of Total station CCGT GT type Original
capacity trains Frame F technology Equipment
MWe capacity MWe Manufacturer
(OEM)
Senoko Converted 365 3 1095 Type F GT26 Alstom
CCGT

Senoko repower 431 2 862 Type F M701F Mitsubishi
(CCP6&7)

TUAS CCGT 367.5 4 1470 Type F M701F Mitsubishi

Seraya CCGT 368 4 1472 Type F V94.3A Siemens
364 (SGT5-
370 4000F)
370
Sembcorp Cogen 6 392.5 2 785 Type F 9FA General
Electric
Sembcorp cogen 400 1 400 Type F GT26 Alstom
(committed)
Keppel Merlimau 420 2 840 Type F GT26 Alstom

GMR 400 2 800 Type F SGT5- Siemens
4000F

5
. KEMA 2009 op cit. Adjustments based on licensed capacity (EMA) as per Table 3 and as updated by SKM
6
Evaluations have been made based on CCGT performance only

PAGE 8


The Vesting Contract procedures published by EMA 7 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.

7
Energy Market Authority, "EMA's procedures for calculating the components of the vesting contracts", March 2011,
Version 1.7

PAGE 9


• 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.
SKM believes that 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).

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 Conditions are the all-
hours average conditions of:

• 29.5ºC dry bulb air temperature,
• 85% Relative Humidity (RH);
• Sea-level;
• 28ºC cooling water inlet temperature.
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, 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
OEMs 8 :

• Alstom;
• Siemens;
• General Electric (GE); and
• Mitsubishi.

8
Original Equipment Manufacturers

PAGE 10


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
configuration 9 .

In order to estimate these performance parameters, the GTPro/GTMaster 10 (Version 22 Release
dated 16 March 2012) thermodynamic analysis software suite was applied. Representative
schematics of the resulting configurations are shown in Appendix C.

3.3. 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 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 longer (considering commercial operating experience).

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 406.0 397.5
M701F 432.4 423.7
GT26 416.1 407.6
SGT5-4000F 389.5 381.7
Average 411.0 402.6
This thermodynamic modelling includes all corrections necessary for:

• Ambient conditions of 29.5ºC;
• Boiler blow-down; and
• Step-up transformer losses.

9
It is noted that the Sembcorp plant is a cogeneration plant. In evaluating the parameters for this review the performance of
plants in CCGT configuration only has been applied.
10
TM, Thermoflow, inc

PAGE 11


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

The impact of gas compression requirements is discussed separately below (Section 3.4).

The capacities and heat rates of operating gas turbine and CCGT power plants degrade from the
time the plant is clean-as-new 11 . The primary drivers for performance degradation are fouling,
erosion and roughening of the gas turbine compressor 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 this effect 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 gas turbine, 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 over the overhaul cycle of the plant as damaged parts are replaced with new
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 4.

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

PAGE 12


Figure 4 Form of CCGT recoverable and non-recoverable degradation
4.5%

4.0%

3.5%
Degradation from clean‐as‐‐new

3.0%

2.5%

2.0%

1.5%

Power degr
1.0%
HR degr

0.5%

0.0%
0 5 10 15 20 25
Years

Based on plants operating up to 93.2% of hours in the year 12 , the degradation allowance amounts
for average capacity degradation rate over the plant's life of 3.05% is suggested (calculated as a
weighted average using the pre-tax real discount rate to weight each year in the plant’s life). Note
that the average capacity degradation is not materially affected by the OEM's nomenclature for
describing major outages for the gas turbine units. Degradation rates are dominated by compressor
fouling rates and the timing of major compressor refurbishments and scouring, similar between
OEM's.

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 6 and Figure 5.

12
Which is the estimated Available Capacity Factor for the plant, from the review for the 2012-13 period

PAGE 13


Table 6 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- 110% 110% 109% 108% 105% 103% 100% 97% 94%
4000F
Average 110% 109% 108% 107% 104% 102% 100% 97% 93%
Figure 5 Effect of ambient temperature on power output
120%
GT26
9FB
115%
701F
4000F
Power, % of Power at Reference Conditions

110% Average

105%

100%

95%

90%

85%

80%
0 5 10 15 20 25 30 35 40
Ambient dry bulb temperature

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 5.98MW. 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.

3.4. Impact of Gas Compression and Resulting Net Capacity

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

PAGE 14


Three of the CCGT configurations noted use natural gas at approximately 35 Barg and one
configuration (the GT26) uses natural gas at approximately 50 Barg at the site boundary. The gas
compressor power requirements calculated for the relevant gas turbines at varying site boundary
gas pressures are shown in Figure 6. Allowances are made for pressure losses between the site
boundary and the gas turbine unit.

Figure 6 Gas compressor power requirements for relevant gas turbines
4,000

3,500

3,000
Gas compressor powr, per unit, kW

2,500

2,000

1,500

1,000
GE, Mitsubishi, Siemens
Alstom

500

‐
20 21 22 23 24 25 26 27 28 29 30

Gas pressure at site boundary, Barg

Data for gas pressures in the TUAS area of Singapore is shown in Figure 7, for the months of
January 2011 to May 2012. The Network 1 pressure may be downstream of a regulator in which
case the upstream pressure will be higher.

PAGE 15


Figure 7 Gas pressures in TUAS area, 2011 to May 2012

45

40

35

30
System pressures, Barg

25

Network 1 Tuas Power Inlet Pressure (Barg)
20
Network 2 Tuas Gatepost Pressure (Barg)

15

10

5

0

May
May
Mar

Nov

Mar
Aug

2012
2011

2011

2011

2011

2011

2011

2011

2011

2011

2011

2011

2011

2012

2012

2012

2012
Feb

Apr

Sep

Oct

Dec

Feb

Apr
Jan
Jan

Jun

Jul

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 13 .

For the purposes of this review it is assumed:

• Gas compressors would be incorporated in a new plant in the TUAS 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 20 Barg; and
• The average pressure at the site boundary during operation is 31.7 Barg in the relevant
period, being the average pressure in the Network 2 from Jan 2010 to date.

13
The introduction of LNG should support local gas pressures. LNG re-gasification plants necessarily incorporate gas
compression.

PAGE 16


On this basis the calculated average gas compressor auxiliary/parasitic load impact is 0.909 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 7.

Table 7 Generation capacity of new entrant CCGT units
Parameter/factor MW
Gross capacity (clean-as-new, reference conditions) 411.0
Less parasitics = net capacity at Reference Conditions (clean-as-new) -8.4 = 402.6
Less allowance for gas compression -0.909
Adjust for 32ºC maximum registered capacity (-1.48%) -5.978
Adjust for average degradation (-3.05%) -12.278
Net capacity 383.47

3.5. Heat Rate
The heat rates of new entrant CCGT configurations, on a clean-as-new condition, and at the
Reference Conditions of 29.5ºC are given in Table 8.

Table 8 Heat rate of new entrant CCGT units (clean-as-new at Reference Conditions
excluding gas compression)
Configuration Net HR, LHV, Net HR, HHV, Net HR, LHV, Net HR, HHV,
GJ/MWh GJ/MWh Btu/kWh Btu/kWh
Frame 9FB 6.295 6.981 5.967 6.617
M701F 6.344 7.035 6.013 6.669
GT26 6.263 6.946 5.936 6.584
SGT5-4000F 6.274 6.958 5.947 6.595
Average 6.294 6.980 5.966 6.616
This thermodynamic modelling includes all corrections necessary for:

• Ambient conditions of 29.5ºC;
• 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 3.3 above, heat rates for CCGT plants are also subject to degradation. A
weighted average heat rate degradation over the plant's life of 1.89% is estimated (weighted by the
pre-tax real discount factor for each year).

PAGE 17


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 9 and Figure 8.

Table 9 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 8 Impact of ambient temperature on heat rate
105%
GT26
9FB
701F
4000F
Average
HR, % of HR at Reference Conditions

100%

95%
0 10 20 30 40
Ambient dry bulb temperature

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.

PAGE 18


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 10 and Figure 9

Table 10 Variation of heat rate with part load (%)
Power 55 % 60% 65% 70% 75% 80% 85% 90% 95% 100%
Average 110.1% 108.3% 106.7% 105.2% 104.0% 102.9% 101.9% 101.2% 100.6% 100%
HR relative
to full load

Figure 9 Variation of heat rate at part load
112%

110%

108% 9FB
Heat rate, % of full load HR

701F

GT26
106%
4000F

Average

104%

102%

100%
60% 70% 80% 90% 100%
Part load

An average load when operating at 86.9% of registered capacity has been applied. This reflects the
shared obligations for providing frequency control ancillary services and is consistent with the
market modelling in Appendix B.

PAGE 19


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
85.6% for which the part-load factor for heat rate would be 1.85%.

An additional adjustment is made to reflect the natural gas used in starts through the year 14 . 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
(+0.5%). It is not considered that the AGC requirement in Singapore is 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 for to account for the gas compressor auxiliary load. As noted in Section
3.4, 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 11.

Table 11 Heat rate of new entrant CCGT units
Parameter/factor Heat rate
Net HR (clean-as-new, reference conditions) - after 6.980 GJ/MWh HHV
recognition of parasitic loads
Adjust for overall part load factor (+1.85%) +0.129
Adjust for average degradation (+1.89%) +0.132
Adjust for starts gas usage (+0.1%) +0.007
Adjust for gas compressor impact +0.017
Adjusted heat rate 7.265 GJ/MWh HHV
Net HR 6,886 Btu/kWh HHV

14
Based on 16 hot starts, 3 warm starts and 0.5 cold starts in an average year. These exclude starts due to economic
shutdowns, the cost of which should be factored into the operator's decision to shut-down.

PAGE 20


4. Capital cost
4.1. Introduction

Capital cost includes:
(i) facility costs (ancillary buildings, 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,
(ii) emergency fuel facilities classified under land and site preparation cost in previous
reviews,
(iii) 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
(iv) discounted through life capital cost classified under miscellaneous cost in previous
reviews.
4.2. Method

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

• 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
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;
• SKM modelled this configuration within the latest version of the PEACE software included
with the GTPro software suite noted in Section 3 above and using the current regional cost
factors in-built into PEACE for Singapore and other relevant countries;
• SKM are also assisting with other large “F” class project developments in the region and
are in discussions (including regarding costs) with OEMs for turnkey supply;
• SKM have considered the latest version of Gas Turbine World Handbook;
• Considering this information 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 is USD760/kW (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 no
modification was considered to be necessary;

PAGE 21


• Models are then established within PEACE for the configurations being evaluated. These
include once through cooling, dual fuel burners, gas compression, 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;
• Further calculations are made to estimate costs for the site specific costs not able to be
modelled in PEACE by direct calculation or by escalating from the previous review.
This method is consistent with the 2011-12 review.

SKM assesses that the capital costs of large CCGT plants for current procurement have reduced
further between the 2011-12 review and this review.

This is notwithstanding that the latest release of the Gas Turbine World Handbook (2012) indicated
that it expected prices to rise 5% to 7% relative to 2011 due to the Handbook’s expected firming up
of gas turbine orders. SKM considers that the Handbooks are not as directly useful as market
soundings and information from other projects are as 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.

A comparison of data presented in recent editions of the Gas Turbine World Handbook for relevant
gas turbines is shown in Table 12. The various qualifications given in the Handbook should be
considered when evaluating this data. 15

Table 12 Gas Turbine World Handbook budget plant prices for CCGT units, USD/kWISO
Gas turbine unit for Volume 26 Volume 27 Volume 28 Volume 29
a single shaft CCGT 2007-08 2009 2010 2012
block Equipment only, Equipment only, FOB Turnkey Turnkey
FOB
Frame 9FB 520 551 494 536
M701F 529 539 491 533
GT26 521 549 497 539
SGT5-4000F 521 550 497 Not listed
SKM has also considered the trends in local construction cost parameters for Singapore as shown
in Table 13 and Figure 10.

15
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.

PAGE 22


Table 13 Local construction cost parameters for Singapore 16
2006 2007 2008 2009 2010 2011 2012
CPI (SingStats) 2009=100 91.3 93.2 99.4 100 102.8 108.2 114.1
Tradesman SGD/h 10 10.5 11.5 12 12 12.5 12.5
Labourer SGD/h 7 7 7.5 8 8 8 8.5
Building Price Index (re previous year) 3% 15% 9% -8% -1% -1% -1%
Industrial factories/wharehouses, owner occ., 900 1025 1200 1950 1700 1750 1600
SGD/m2
Concrete (foundations) SGD/m3 88 92 160 160 150 127 137
Structural steel, UB, UC etc erected SGD/t 2700 3100 4500 6000 5200 5280 5230

Figure 10 Trends in Singapore local construction cost parameters, 2010 = 100
140%

120%

100%
Index relative to 2010

80%
CPI (SingStats) 2010=100

Tradesman SGD/h
60%
Labourer SGD/h

Building Price Index
40%
Industrial factories/wharehouses, owner occ.,
SGD/m2
Concrete (foundations) SGD/m3
20%

Structural steel, UB, UC etc erected GD/t

0%
2006 2007 2008 2009 2010 2011 2012

The apparent local construction costs are slightly below those of 2010 for the 2011-12 review.

16
Successive issues of Rawlinson’s “Australian Construction Cost Handbook”, International Construction Costs table

PAGE 23


4.3. Initial capital cost

Modifications are applied to make the unit cost applicable to this study 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; and
• Allowances for fuel tanks are added on a shared (two-unit) basis.
The resulting EPC cost for the plant (excluding external connections) is SGD479.2M per unit as
shown in Table 14. This cost is on an "overnight" basis 17 .

17
That is, excluding Interest during Construction (IDC).

PAGE 24


Table 14 EPC capital cost summary (per unit) for 2012-13, with comparison against the 2009-
2010 review and the 2011-12 review 18
Project Cost Summary 2009- 2011-12 Current Comments
2010 review review
review SGD k SGD k
SGD k
I Specialized Equipment 345,000 292,400 245,345
II Other Equipment 47,100 9,668 13,334
III Civil 29,106 28,572 Shared
IV Mechanical 41,306 32,955
V Electrical Assembly & Wiring 9,546 5,703
VI Buildings & Structures 13,217 11,966 Shared, except
turbine hall
VII Contractor's Engineering & 7,000 19,866 20,679
commissioning
VIII Contractor's Soft & 20,000 91,099 78,681
Miscellaneous Costs (including
Contractor's contingencies, margins
and preliminaries)
Transport 6,900 Included Included
Gas compressors 11,070 9,062
Adjust for OT C/W system 6,700 6,676 6,544 Shared
Jetty & unloading 10,000 7,972 7,813 Shared
Fuel tanks 19,000 18,933 18,556 Shared
EPC equivalent capital cost 461,700 550,859 479,212
excluding connections
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.

Average load growth is projected to be less than 200MW/year through 2016, and peak demand
growth to be 240-254MW/y, and hence it would be expected that additions of base-load plant in
nominally 400MW blocks would be spaced 1.5 years apart or more, unless there are retirements
from the market.

18
2009 values have been allocated to equivalent categories on an estimated basis

PAGE 25


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) is typically materially
lower with a "2+1" arrangement than for two "1+1" blocks. However, this depends on the load
growth being sufficiently high to justify the additional capacity being constructed immediately after
the first unit. This is not included in this analysis.

4.4. Through-life capital costs

Capital costs of plant maintenance through the overhaul cycle of the gas turbine and steam turbine
are included in Sections 5.1 and 5.2.

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 15:

Table 15 Through-life capital expenditure (per unit)
Area Time within project Estimate, per unit Discounted equivalent,
SGDM/unit (pre-tax real
WACC=3.2%), per unit
Distributed control system 15 years 7 SGDM real 4.4
(DCS)
Gas turbine rotor 15 years (100,000 to 12.7 SGDM real 8.0
150,000 operating hours) (USD10M)
Total 12.3
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.

4.5. 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.

PAGE 26


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 $245 and $306 per square metre 19 . This implies that the cost of a 12.5Ha
parcel of land is between $30.625 million and $38.25 million. Water frontage fees range from
$1,226 to $1,839 per metre per year. For a 200 metre waterfront, the annual cost is between
$245,200 and $367,800. Using the average annual cost at a discount rate of 3.2% over 20 years,
this gives an equivalent capital cost of $4.48 million. Total capital cost for land assuming a mid-
point land cost is thus $38.91 million.

Site preparation cost is relatively minor. In 2010 for the 2011-12 review, this was assessed to be
$1.5million. For the current review, we have assumed this to be $2 million. Total land and site
preparation costs are thus $40.91million and a per unit cost of SGD$20.46 million.

The land and preparation cost for the 2010-12 review was SGD13.65M/unit.

4.6. 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
16. SKM has taken into consideration in this assessment the cost of connecting two 400MW
CCGT units using the configuration shown in Figure 11.

Table 16 Electrical connection costs (2 units)
Item Connection Cost Components Cost (SGDM)
1 Standard Connection Charge (to SPPG) SGD 38.4
50,000/MW
2 230kV Switchgear GIS GIS 6 off 17.8
Notes:
breaker and a half configuration
include switch house but exclude generator
transformer
3 XLPE Underground Cable (based on 2x 4.51/km 2km 9.0
1000MVA circuits of 1 km length, direct burial)
Total 65.1

19
JTC's Land Rents and Prices with effect from 1 January 2012, http://www.jtc.gov.sg/Pages/JtcIndustrialLand_Price.aspx

PAGE 27


Based on the standard Power Grid connection charge, the cost of electrical connection including
the cost of the typical 230kV switchgear and XLPE underground cable is estimated to be
SGD32.6M per unit.

The connection cost in the 2011-12 review was SGD31.6M/unit.

Figure 11 Assumed electrical connection configuration (items per Table 16)

The gas connection costs are escalated from the 2010 report to SGD13.3M or SGD6.65M per unit.

Total connection cost is thus SGD78.4M, or SGD39.2M/unit.

4.7. 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 17:

PAGE 28


Table 17 Owner's costs allowances (after financial closure)
Area Percentage Cost, per
of EPC + unit
connection (SGDM)
cost
Owners Engineering 3% 15.6
Owners "minor items" 3% 15.6
Initial spares 2% 10.4
Start-up costs 2% 10.4
Construction related 1% 5.2
insurance etc.
Total 57.0
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 4.3.

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 5.1).

PAGE 29


4.8. 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 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 18.

Table 18 Owner's costs allowances prior to Financial Closure
Area Percentage Cost, per unit
of EPC + (SGDM)
connection
cost
Permits, licenses, fees 2% 10.4
Legal & financial advice 2% 10.4
and costs
Owner's engineering and 2% 10.4
in-house costs
Total 31.1
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.

PAGE 30


5. Operating costs
5.1. Fixed annual running cost

An assessment of the fixed annual cost of operating a CCGT station is shown in Table 19.

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 etc are 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 19 Fixed annual operating cost allowance
Area SGDM for 2
units

Manning 4.53
Allowance for head office services 2.72
Fixed maintenance and other fixed 11.501
operations 20
Starts impact on turbine maintenance 0.785
Distillate usage impact on turbine 0.064
maintenance
EMA license fee (fixed) 0.05778
Working capital (see below) 8.322
Emergency fuel usage 2.448
Property Tax 1.384
Insurance 4.792
Total (for 2 units) per year 36.594
Costs per unit would thus be SGD18.297M 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.

PAGE 31


Manning costs have been estimated based on 42 personnel covering 2 units at
SGD107,700/person/year. The unit rate considers the cost allowed in 2010 for the 2011-12 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). This index 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 index 21
120%

100%

80%
Labour cost indec (relatie to 2010)

60%

40%

20%

0%
1998 2000 2002 2004 2006 2008 2010 2012 2014

21
Indexed produced using SingStats “Yearbook of statistics Singapore 2011 Table 10.7 and 10.8 "Chemical and chemical
products" manufacturing” average remuneration.

PAGE 32


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.
The manning and head office costs are bundled (with non-fuel working capital costs) are based on
60% of the manning cost allowance per the 2011-12 review.

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 1.75 EUR/CCGT-MWh at nominal full load based on discussions with the
OEMs. Allowing for part load adjustments the equivalent cost is EUR469.7/EOH. 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 50 starts/unit and 10
EOH/start, the cost is SGD392,604/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 SGD32,053/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 the draft report assumed
prices of 29.25 SGD/GJ and 22.10 SGD/GJ for distillate and gas, respectively are applied.

This distillate cost assumption is based on USD977.6/t (USD128.29/bbl) for this draft report based
on the average of daily rates for Gasoil (0.5%) from Dec 2011 through Feb 2012. A handling and
delivery cost based on the allowance of USD6.02/bbl is added to give a delivered distillate cost of
USD134.31/bbl, or SGD29.25/GJ.

PAGE 33


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), 8.8PJ at a distillate cost of SGD29.25/GJ
and a pre-tax real WACC of 3.2% gives a working capital cost of SGD8.211M/year; 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 SGD3.46M and the working capital
cost (using a pre-tax real WACC of 3.2%) is SGD0.11M/year.
Emergency fuel usage is a notional amount of emergency fuel usage for testing, tank turnover etc.
Calculated as 1% of the annual fuel usage and using a cost based on the extra cost of distillate over
natural gas (SGD29.25/GJ vs SGD22.10/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 cost 22 . Note is also made of the IRAS circular regarding
property taxes on plant and machinery 23 . 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 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 SGD276M (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 2011-2012 review is shown in Table 20.

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.

PAGE 34


Table 20 Fixed annual operating cost allowance comparison, SGD Millions for 2 units
Area 2011-12 review Current review

Manning 4.20 4.53
Allowance for head office services 2.52 2.72
Fixed maintenance and other fixed 11.501
operations 15.631
Starts impact on turbine maintenance 0.935 0.785
Distillate usage impact on turbine 0.064
maintenance 0.0763
EMA license fee (fixed) 0.05 0.058
Working capital 13.526 8.322
Emergency fuel usage 1.497 2.448
Property Tax 1.037 1.384
Insurance 5.509 4.792
Total (for 2 units) per year 44.981 36.594

5.2. 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 21.

PAGE 35


Table 21 Variable non fuel costs
Area SGD/MWh Notes
Gas turbine 3.42 Based on approximately EUR1.75/MWh of total plant
output, adjusted for part load factor
Steam turbine 0.5
Balance of plant, 0.5
chemicals,
consumables
Town Water 0.052 For a salt water cooled plant the town water costs are
typically small. Based on 0.1t/MWh usage and a cost of
0.52 SGD/t 24 .
EMC fees 0.343 Based on EMC's Admin Fees of S$29.027 million / 2, and
a forecast wholesale volume of 42,257 GWh.
PSO 0.221 From EMC website 25 for FY2010-11
EMA license fee 0.179 Advised by EMA
(variable)
Total 5.21
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 the variable operating cost would reduce
by approximately SGD3.92/MWh and the fixed operating cost would increase by approximately
SGD19.16M/y (for 2 units). This would not change the LRMC value calculated.

A comparison with the values shown in the 2011-2012 review is shown in Table 22.

Table 22 Variable operating cost allowance comparison, SGD/MWh
Area 2011-12 Current
review review
Gas turbine 4.64 3.42
Steam turbine 0.5 0.5
Balance of plant, chemicals, consumables 0.5 0.5
Town Water 0.2 0.052
EMC fees 0.3343 0.343
PSO 0.2205 0.2212
EMA license fee (variable) 0.155 0.179
Total 6.55 5.21

24
http://www.pub.gov.sg/general/Pages/WaterTariff.aspx for “Industrial Water Tariff”
25
http://www.emcsg.com/psobudgetandfees

PAGE 36


6. Other parameters
6.1. Build duration

Current expected build duration for this type of plants is 30 months. This is unchanged
from the 2011-2012 review.

6.2. Economic life

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

The economic life has been assessed at 20 years as discussed in Appendix B (versus 24 years in the
2011-12 review).

6.3. 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 (Senoko Energy's CCP 3 to 5, YTL
PowerSeraya's CCP 1 and 2 and Tuas Power Generation's CCP1 to 4) for the 12 months leading up
to the base month. .

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
72.8%.

PAGE 37


7. Results – vesting contract parameters
7.1. Introduction

The LRMC resulting from the inclusion of the parameters considered in this report along with the
financial parameters that are to be determined by others will be calculated by EMA.

For the purposes of comparing the impacts of the changes in technical parameters, a calculation is
included of the LRMC, made using assumptions for financial parameters where necessary pending
their calculation by others.

7.2. Summary of technical parameters

Table 23 Summary of recommended technical parameters and previous values
Item Parameter 2011-12 Value 2013-14 Value
6 Economic capacity of the most economic 381 383.47MW net at 32oC
technology in operation in Singapore (MW)
7 Capital cost of the plant identified in item 6 1053 1004.21 USD/kW
($US/kW)
8 Land, infrastructure and development cost of 152.0M SGD 147.81M
the plant identified in item 6 ($Sing million)
11 HHV Heat Rate of the plant identified in item 7010 6886 btu/kWh net HHV
6 (Btu/kWh)
12 Build duration of the plant identified in item 6 2.5 2.5 years
(years)
13 Economic lifetime of the plant identified in 24 20 years
item 6 (years)
14 Average expected utilisation factor of the 74.9% 72.8%
plant identified in item 6, i.e. average
generation level as a percentage of capacity
(%)
15 Fixed annual running cost of the plant 22.49 18.297 M SGD
identified in item 6 ($Sing)
16 Variable non-fuel cost of the plant identified in 6.55 5.21 SGD/MWh
item 6 ($Sing/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;

• A reduction in WACC, which reduces the capital contribution, working capital costs and
other minor parameters;

• An increase in the SGD / USD exchange rate; and

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