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ENERGY MARKET AUTHORITY Review of the Vesting Contract Technical Parameters for the period 1 January 2019 to 31 December 2020
DRAFT
17 July 2018
DRAFT
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: DRAFT 4.0
Prepared by: Rohan Zauner Document reference:
DRAFT
1
This report is prepared for the EMA in connection with PA's review of the Vesting Contract price
parameters for 2019 and 2020. 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
DRAFT
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 2019 and 2020. Jacobs Group (Australia) Pty Ltd (Jacobs), formerly Sinclair Knight Merz (SKM), has been engaged by PA Consulting to provide the technical parameters.
LRMC technical parameters
The following values are recommended by Jacobs for use in the Vesting Contract parameters for
2019-20.
Table 1 Summary of recommended technical parameters
Item Parameter 2019-20 Value
6 Economic capacity of the most economic
technology in operation in Singapore (MW)
427.86 MW net at 32oC
7 Capital cost of the plant identified in item 6
($US/kW)
836.74 USD/kW
8 Land, infrastructure and development cost of the
plant identified in item 6 ($Sing million)
SGD 149.26M
11 HHV Heat Rate of the plant identified in item 6
(Btu/kWh)
6983.7 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)
25 years
14 Average expected utilisation factor of the plant
identified in item 6, i.e. average generation level as
a percentage of capacity (%)
63.42%
15 Fixed annual running cost of the plant identified in
item 6 ($Sing)
20.80M SGD
16 Variable non-fuel cost of the plant identified in item
6 ($Sing/MWh)
7.11 SGD/MWh
24a Carbon price ($Sing/tonne CO2-e) 5 SGD/t
24b Carbon emissions factor (tonnes CO2-e / GJ HHV) 50.03 kg/GJ HHV
EXECUTIVE SUMMARY
DRAFT
3
CONTENTS
DISCLAIMER 1
EXECUTIVE SUMMARY 2
LRMC technical parameters 2
1 INTRODUCTION 7
1.1 Financial parameters 7
1.2 Disclaimer 8
2 PERFORMANCE PARAMETERS 9
2.1 Existing generators 9
2.2 Generating technology 10
2.3 Capacity per generating unit 12
2.4 Impact of gas compression 16
2.5 Net capacity 18
2.6 Heat Rate 19
3 CAPITAL COST 23
3.1 Method 23
3.2 Initial capital cost 28
3.3 Through-life capital costs 30
3.4 Land and Site Preparation Cost 30
3.5 Connection Cost 31
3.6 Owner's costs after financial closure 32
3.7 Owner's costs prior to Financial Closure 33
4 OPERATING COSTS 35
4.1 Fixed annual running cost 35
4.2 Variable non-fuel cost (excluding carbon price) 38
4.3 Carbon price 40
5 OTHER PARAMETERS 42
5.1 Build duration 42
5.2 Economic life 42
5.3 Average expected utilisation factor 42
6 RESULTS – VESTING CONTRACT PARAMETERS 44
6.1 Introduction 44
6.2 Summary of technical parameters 44
DRAFT
4
6.3 Calculated LRMC 45
APPENDICES 47
A PRESCRIBED PROCEDURES 48
B ECONOMIC LIFE 54
C THERMODYNAMIC ANALYSIS 55
DRAFT
5
FIGURES AND TABLES
FIGURES
Figure 1 Singapore CPI data 8
Figure 2. Form of CCGT recoverable and non-recoverable degradation 15
Figure 3 Effect of ambient temperature on power output 16
Figure 4 Gas compressor power requirements for relevant gas turbines versus network gas
pressure 17
Figure 5 Gas pressures in TUAS area 17
Figure 6 Impact of ambient temperature on heat rate 20
Figure 7 Variation of heat rate at part load 21
Figure 8. Capex estimation method 25
Figure 9 Trends in Singapore local construction cost parameters, 2014 = 100 27
Figure 10 BCA Tender Price Index, 2010 = 100 28
Figure 11 Assumed electrical connection configuration (items per Table 18) 32
Figure 12 Labour cost index 36
Figure 13 Performance analysis - Ansaldo "F" class CCGT, clean-as-new, At Reference
conditions 56
Figure 14 Performance analysis - GE "F" class CCGT, clean-as-new, At Reference conditions57
Figure 15 Performance analysis - Mitsubishi "F" class CCGT, clean-as-new, At Reference
conditions 58
Figure 16 Performance analysis - Siemens "F" class CCGT, clean-as-new, At Reference
conditions 59
TABLES
Table 1 Summary of recommended technical parameters 2
Table 2 Finance parameters applied 8
Table 3 Registered capacity, large CCGT units 9
Table 4 Existing Singapore station parameters (large F class CCGT units) 10
Table 5 Generation capacity of new entrant CCGT units (clean-as-new at Reference Conditions,
including gas compression impacts) 13
Table 6 Auxiliary loads incorporated within GTPro models, kW 13
Table 7 Variation in net power output with ambient temperature (relative to Reference
Conditions) 15
Table 8 Gas pressure trends, kPag 18
DRAFT
6
Table 9 Generation capacity of new entrant CCGT units (averaged over selected four gas
turbine models) 19
Table 10 Heat rate of new entrant CCGT units (clean-as-new at Reference Conditions including
gas compression) 19
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 22
Table 14 Gas Turbine World Handbook budget plant prices for CCGT units, USD/kW ISO 26
Table 15 Local construction cost parameters (nominal) for Singapore 26
Table 16 EPC capital cost summary (per unit) for 2019-20, with comparison against earlier
reviews 29
Table 17 Through-life capital expenditure (per unit) 30
Table 18 Electrical connection costs (2 units) 31
Table 19 Owner's costs allowances (after financial closure) 33
Table 20 Owner's costs allowances prior to Financial Closure 34
Table 21 Fixed annual operating cost allowance 35
Table 22 Fixed annual operating cost allowance comparison, SGD Millions for 2 units 38
Table 23 Variable non fuel costs (excluding carbon price) 39
Table 24 Variable operating cost allowance comparison, SGD/MWh 39
Table 25 Carbon Emissions Factor, kg/GJ HHV 40
Table 26 Calculated impact of the carbon price 40
Table 27 Recommended amendments to the vesting contract procedures 41
Table 28 Recommended indexation for Item 7 for the mid-term review 42
Table 29 Recommended indexation for Item 8 for the mid-term review 43
Table 30 Summary of recommended technical parameters and previous values 44
Table 31 Assumed financial parameters for the LRMC calculation 45
Table 32 Calculated LRMC for 2019-20 45
Table 33 Comparison of the calculated LRMC with the previous estimate, SGD/MWh 46
Table 34 Excerpt from Vesting Contract Procedures 48
DRAFT
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 2019 through to 31 December 2020.
EMA has engaged PA Consulting undertake two tasks (with Task 2 being a potential further review if called for by EMA and which would be the subject of a separate report):
Task 1:
• Conduct a comprehensive review of the vesting price parameters, as specified in section 2.3 of the EMA's Procedures for Calculating the Components of the Vesting Contracts (the "Procedures paper"):
– Recommend values for the parameters specified by Items 6, and 11 to 16 for the 2-year period, 1 January 2019 - 31 December 2020
– Recommend values for the parameters specified by Items 7 and 8 for the 1-year period, 1 January 2019 - 31 December 2019, and
• Propose a methodology, utilising available information, to determine a capital cost index, as set out in Section 3.8(A) of the Procedures, that can be used to scale the parameter values for items 7 and 8 for setting the vesting price for the 1-year period, 1 January 2020 to 31 December 2020.
• Review the financial parameters, which are presented in a separate report.
PA Consulting has engaged Jacobs to provide the technical parameters.
This review of the vesting contract parameters follows the method adopted by Jacobs in the review of parameters for the period 1 January 2015 to 31 December 2016 (the “2015-16” 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 eighth of these two yearly reviews is the subject of this project, covering the period 1 January 2019 to 31 December 2020.
1.1 Financial parameters
Financial parameters for use in the technical parameter analysis are shown in Table 2.
1 INTRODUCTION
DRAFT
8
Table 2 Finance parameters applied
Parameter Value Notes
WACC 6.15% post-tax, nominal
5.78% pre-tax, real
From financial parameters report
CPI 1.54% Average year-on-year core inflation,
Jan 2018, Feb 2018, Mar 2018.
Trend data is shown in Figure 1
Gas price $14.11 SGD/GJ Advised by EMA. Weighted gas
price (pipeline and LNG)
Exchange rates 1.32 SGD/USD
1.62 SGD/EUR
Average bid and ask, daily, Jan
2018, Feb 2018, Mar 2018.
Figure 1 Singapore CPI data1
1.2 Disclaimer
This report has been prepared for the benefit of EMA for the purposes of setting the vesting contract
price for the 2019 to 2020 period. This report may not be relied upon by any other entity and may not
be relied upon for any other purpose.
1 Monthly data Department of Statistics, Singapore, https://www.singstat.gov.sg/-/media/files/news/cpiapr2018.pdf and earlier
editions
DRAFT
9
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 CCGT3 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
YTL PowerSeraya CCP1 368 2002 EMA/GE/016
YTL PowerSeraya CCP2 364 2002 EMA/GE/016
2 http://www.ema.gov.sg/Licencees_Electricity_Generation_Company.aspx
3 Combined Cycle Gas Turbine
2 PERFORMANCE PARAMETERS
DRAFT
10
Large CCGT units Reg. Cap,
MW
Date Licence
YTL PowerSeraya CCP3 370 2010 EMA/GE/016
YTL PowerSeraya 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
Tuaspring TSPBLK1 395.7 2016 EMA/GE/015
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)4
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
Cogen5
392.5 2 785 Type F 9FA General
Electric
Sembcorp
Cogen
403.8 1 400 Type F GT26 Alstom
4. KEMA 2009 op cit. Adjustments based on Licenced capacity (EMA) as per Table 3 and as updated by Jacobs
5 Evaluations have been made based on CCGT performance only
DRAFT
11
Power
station
Train
capacity
MWe
Number
of trains
Total station
Frame F
capacity
MWe
CCGT
technology
GT type Original
Equipment
Manufacturer
(OEM)
Keppel
Merlimau
420 2 840 Type F GT26 Alstom
PacificLight
Power
400 2 800 Type F SGT5-
4000F
Siemens
Tuaspring 395.7 1 395.7 Type F SGT5-
4000F
Siemens
The Vesting Contract procedures published by EMA6 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.
6 Energy Market Authority, "EMA's procedures for calculating the components of the vesting contracts", September 2015,
Version 2.3
DRAFT
12
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. This is notwithstanding that Jacobs expect that a new entrant, if one were coming into
the market, would choose a later, more efficient and cost-effective technology now available, based on
“H” or “J” class gas turbines. However, these units would all likely generate at least 700MW in
Singapore conditions, and do not meet the requirements of the Vesting Contract procedures.
Jacobs 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 Conditions7 are the all-hours
average conditions of:
• 29.5ºC dry bulb air temperature,
• 85% Relative Humidity (RH);
• Sea-level;
• 29.2ºC cooling water inlet temperature8.
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 previous reviews, 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 OEMs9:
• Alstom (now part of GE however the relevant gas turbine model is now provided by Ansaldo);
• 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 configuration.
In order to estimate these performance parameters, the GTPro/GTMaster10 (Version 27)
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 Jacobs has decided not to apply the very latest announced models of the GE gas turbine (the
9F.0611) but to instead select the variants that have been available in the market for a longer time
(considering commercial operating experience).
7 As applied in the 2015-16 review
8 EMA has previously provided the average seawater temperature for TUAS area to be approximately 29.2 ºC
9 Original Equipment Manufacturers
10 TM, Thermoflow, Inc.
11 Jacobs are not aware of any sales of this unit
DRAFT
13
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 capacity and efficiency than the units operating in Singapore at present and
higher 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 theoretical new entrant that uses the most economic generation technology in operation
in Singapore and contributes to more than 25% of the total demand. In 2019-2020 “H” or “J” class gas
turbines will not form 25% of 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, including gas
compression impacts)
Configuration Gross MW Net MW
Frame 9FB (now
designated 9F.05)
410.6 402.2
M701F4 528.2 516.2
GT26 456.6 445.1
SGT5-4000F 437.8 429.4
Average 458.3 448.2
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 9F.05 701F
GT fuel compressor(s) (at average gas pressure) 0 2243.1 50.02 1489.2
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) 2673.7 2983.9 2777.6 3587
Condensate pump(s) 276.9 305.4 273 310
Cooling water pump(s) 1149.3 1308.1 1130.6 1328.8
Aux. from PEACE running motor/load list 1194 1436.5 1154 1454.5
DRAFT
14
SGT5-
4000F
GT26 9F.05 701F
Miscellaneous gas turbine auxiliaries 659.1 663.2 598.7 778.5
Miscellaneous steam cycle auxiliaries 78.77 88.65 79.72 91.8
Miscellaneous plant auxiliaries 218.9 228.3 205.3 264.1
Constant plant auxiliary load 0 0 0 0
Program estimated overall plant auxiliaries 6251 9257 6269 9304
Transformer losses 2189.2 2283.2 2052.8 2640.8
Total auxiliaries & transformer losses 8440.2 11540.2 8321.8 11944.8
The impact of gas compression requirements is included and is discussed further below (Section 2.4).
The capacities and heat rates of operating gas turbine and CCGT power plants degrade from the time
the plant is clean-as-new12. 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 or replacement 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 2. Degradation rates for base and
intermediate loaded CCGT units are not considered to be materially affected by load factor or capacity
factor.
12 Refer GE publication “Degradation curves for Heavy Duty Product Line Gas Turbines” for example
DRAFT
15
Figure 2. Form of CCGT recoverable and non-recoverable degradation
Based on plants operating up to 93.2% of hours in the year13, 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 3.
Table 7 Variation in net power output with ambient temperature (relative to Reference Conditions)
Config. Ambient temperature (dry bulb), ºC
24 25 26 27 28 29 30 31 32
701F 102.1% 101.7% 101.3% 101.0% 100.5% 100.2% 99.8% 99.4% 99.0%
GT26 102.9% 102.4% 101.9% 101.4% 100.8% 100.3% 99.7% 99.2% 98.6%
9F05 104.0% 103.3% 102.6% 101.9% 101.2% 100.4% 99.6% 98.8% 97.9%
4000F 103.3% 102.7% 102.1% 101.5% 100.9% 100.3% 99.7% 99.1% 98.5%
Average 103.1% 102.5% 102.0% 101.4% 100.9% 100.3% 99.7% 99.1% 98.5%
13 Which is the estimated Available Capacity Factor for the plant
DRAFT
16
Figure 3 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 6.65MW. 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 460.1MW/unit.
2.4 Impact of gas compression
Gas compression is required for new entrant “F” class CCGT plants in Singapore.
Two of the CCGT configurations noted (701F and 9F.05) use natural gas at approximately 30 barg,
the SGT5-4000F at 40 barg and the GT26 uses natural gas at approximately 50 barg. The gas
compressor power requirements calculated for the relevant gas turbines at varying network gas
pressures are shown in Figure 4. An additional (approx.) 7 bar pressure drop allowance from the
system pressure measurement point to the site boundary (as included in GTPro) is included in the
calculation.
DRAFT
17
Figure 4 Gas compressor power requirements for relevant gas turbines versus network gas pressure
Data for gas pressures in the TUAS area of Singapore is shown in Figure 5, for the period from
January 2017 onwards. The Network 1 pressure may be downstream of a regulator in which case the
upstream pressure will be higher.
Figure 5 Gas pressures in TUAS area
DRAFT
18
Table 8 Gas pressure trends14, 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
2014 1,915 3,925 3,125 3,779
2015 3,863 3,929 3,201 3,872
2016 (part) 3,844 3,929 3,494 3,850
2017 3,841 3,841 2,919 3,737
2018 (to 27 Apr) 3,882 3,882 3,385 3,819
The data indicates that gas compression is sometimes required under current conditions with
minimum conditions rising after the commissioning of the LNG facility in 2013. Should the system
pressures reduce (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 incoming gas
pressures from those presently seen. It is assumed for capital cost estimation purposes that
compressors would be capable of operating from a site boundary gas pressure as low as 22 Barg;
and
• The average pressure at the site boundary during operation is 31 Barg (30 Bara) in the relevant
period, being the average pressure in the Network 2 in 2017 and 2018 of 37.6 Barg less an
allowance for pressure drop and any other factor to the site boundary.
The auxiliary load impact of the gas compressors operating from the average pressure noted has
been included in the performance analysis of each of the gas turbines considered.
2.5 Net capacity
The resulting net capacity calculation after considering the above is shown in Table 9.
14 2014 to 2016 data from WSP Parsons Brinkerhoff report, op cit
DRAFT
19
Table 9 Generation capacity of new entrant CCGT units (averaged over selected four gas turbine models)
Parameter/factor MW
Gross capacity (clean-as-new, reference conditions) 458.3
Less parasitics = net capacity at Reference Conditions (clean-as-new) -10.1 = 448.2
Less allowance for gas compression Incl.
Adjust for 32ºC maximum registered capacity (-1.48%) -6.65
Adjust for average degradation (-3.06%) -13.7
Net capacity 427.9
2.6 Heat Rate
The heat rates of new entrant CCGT configurations, on a clean-as-new condition, and at the
Reference Conditions of 29.5ºC air temperature are given in Table 10.
Table 10 Heat rate of new entrant CCGT units (clean-as-new at Reference Conditions including gas compression)
Configuration Net HR, LHV,
GJ/MWh
Net HR,
HHV,
GJ/MWh
Net HR,
LHV,
Btu/kWh
Net HR,
HHV,
Btu/kWh
Frame 9F.05 6.211 6.888 5.887 6.529
M701F 6.222 6.900 5.898 6.540
GT26 6.063 6.724 5.747 6.373
SGT5-4000F 6.149 6.819 5.828 6.464
Average 6.161 6.833 5.840 6.477
This thermodynamic modelling includes all corrections (within GTPro) necessary for:
• Ambient conditions and average sea water temperature of 29.2ºC;
• Boiler blow-down
• Gas compressor auxiliary load as discussed in Section 2.4; and
• Step-up transformer losses.
No further allowances need to be made for these factors except as discussed below regarding
ambient temperature.
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 6.
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Table 11 Variation in net heat rate with ambient temperature (relative to Reference Conditions)
Ambient temperature (dry bulb), ºC
Config. 24 25 26 27 28 29 30 31 32
701F 100.1% 100.1% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0%
GT26 99.9% 99.9% 99.9% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0%
9F05 99.9% 99.9% 99.9% 99.9% 100.0% 100.0% 100.0% 100.1% 100.2%
4000F 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.1%
Average 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.1%
Figure 6 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 32oC Standing Capability
Data criterion for capacity 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 7
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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,
109.8% 108.0% 106.4% 105.1% 103.9% 102.9% 102.0% 101.2% 100.5% 99.8%
Figure 7 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 63.42% is discussed in Section 5.3. Applying the Available Capacity Factor of 93.2% (i.e.
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 63.42% / 93.2% = 68.05%. 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 67.0%for which the part-load factor for heat
rate would be 5.8%.
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 was 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.
The resulting overall heat rate calculated is shown in Table 13.
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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
6.833 GJ/MWh HHV
Adjust for overall part load factor (+5.8%) +0.399
Adjust for average degradation (+1.90%) +0.130
Adjust for starts gas usage (+0.1%) +0.007
Adjust for gas compressor impact Incl.
Adjusted heat rate 7.368 GJ/MWh HHV
Net HR 6,984 Btu/kWh HHV
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23
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 8.
Jacobs has considered the estimated current specific capital costs (on a greenfields EPC basis) for a
specific generic CCGT configuration that Jacobs 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 is based on projects Jacobs has been involved with
in South-East Asia over the last two years (which generally involve “H” class units) and making a
judgement adjustment for “F” class technology.
Jacobs 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
estimate for the generic, plant described.
Jacobs has also considered the latest version of Gas Turbine World Handbook, published in 201815
but does not believe the indicative prices in the handbook reflect the current market in Asia.
Considering this information Jacobs assesses that the current EPC cost (excluding connections and
on an “overnight basis”) of a "standard" single-unit "F" class CCGT unit for a South-East Asian location
has reduced to $500 USD/kW basis based on net ISO output.
15 Volume 33, January 2018
3 CAPITAL COST
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The global market for sales of large gas turbines is presently extremely depressed and the major
OEMs are under severe pressure in their large gas turbine divisions. For example, according to
Siemens16:
Global demand for large gas turbines (generating more than 100 megawatts) has fallen
drastically and is expected to level out at around 110 turbines a year. By contrast, the
technical manufacturing capacity of all producers worldwide is estimated at around 400
turbines.
These market conditions have resulted in continuing downwards price pressure in the large gas
turbine sales market.
Jacobs 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 27, a
reduction of the “Specialised Equipment” to 88% of its default value to reflect current anticipated
market conditions. 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.
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.
16 Siemens Press Release 16 Nov 2017 at
https://www.siemens.com/press/pool/de/pressemitteilungen/2017/corporate/PR2017110073COEN.pdf
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Figure 8. Capex estimation method
This method is consistent with the previous reviews undertaken by Jacobs.
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
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
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considered when evaluating this data.17. Jacobs SKM considers that the Handbooks are not as
directly useful as local market information 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. 28
2010
Vol. 29
2012
Vol. 30
2013
Vol. 31
2014-15
Vol. 32
2016-17
Vol. 33
2018
Frame 9FB 494 536 572 667 660 Not listed
M701F 491 533 560 670 659 659
GT26 497 539 Not listed 675 667 683
SGT5-4000F 497 Not listed Not listed Not listed Not listed Not listed
Generalised power generation market indices such as the US or European Power Construction Cost
Index are not considered sufficiently reflective of the specific large-CCGT technology required for
basing the capital cost upon for this review.
Jacobs has also considered the trends in local construction cost parameters for Singapore as shown
in Table 15 and Figure 9.
Table 15 Local construction cost parameters (nominal) for Singapore18
2010 2011 2012 2013 2014 2015 2016 2017 2018
CPI (SingStats) 90.2 94.4 98.5 99.9 100.1 99.2 99.4 99.7 99.3
(Apr)
MAS Core Inflation 92.8 95.2 97.0 99.0 100.3 100.8 102.0 103.4 104.2
(Apr)
Tradesman SGD/h 12 12.5 12.5 12.5 13 13.5 13.5 13.5 14
Labourer SGD/h 8 8 8.5 9 9.5 10 10 10 10.5
Building Price Index (re previous
year)
-1% -1% -1% -1% 2% 2% 0% -2% -1%
Industrial factories/warehouses,
owner occ., SGD/m2
1700 1750 1600 1750 1750 1750 1750 1700 1750
Concrete (foundations) SGD/m3 150 127 137 140 143 145 143 135 131
Structural steel, UB, UC etc. erected
SGD/t
5200 5280 5230 5200 5300 5300 5200 5100 4700
17 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.
18 Successive issues of Rawlinson’s “Australian Construction Cost Handbook”, International Construction Costs table
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Figure 9 Trends in Singapore local construction cost parameters, 2014 = 100
Since Jacobs last undertook this review in 2014, the cost of construction labour has risen however the
costs of key construction materials (concrete and structural steel) have fallen. The cost of a
completed industrial building has been static in nominal terms.
For minor capital cost elements of a civil/structural nature 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 Singapore19. This same treatment has been applied
in this review.
As shown in Figure 10, the Tender Price Index has fallen since Jacobs’ previous review, from 106.8 in
2014 to 97.4 in (1st Q) 2018. The cost of the minor items is thus indexed in nominal terms from the
previous review by 91.2%.
19 https://www.bca.gov.sg/keyconstructioninfo/others/free_stats.pdf
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Figure 10 BCA Tender Price Index, 2010 = 100
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.
The resulting EPC cost for the plant (excluding external connections) is SGD463,378M per unit as
shown in Table 16. This cost is on an "overnight" basis20.
20 That is, excluding Interest during Construction (IDC).
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Table 16 EPC capital cost summary (per unit) for 2019-20, with comparison against earlier reviews
Project Cost Summary 2013-14
review
SGD k
2015-16
review
SGD k
2017-18
review21
SGD k
2019-20
review
SGD k
Comments
I Specialized Equipment 240,505 214,780 242,377 195,515
II Other Equipment 11,306 11,389 11,489 28,923
III Civil 24,925 25,802 31,771 27,443 Shared
IV Mechanical 35,081 33,580 37,470 37,610
V Electrical Assembly &
Wiring
5,099 7,123 8,905 8,995
VI Buildings &
Structures
10,455 9,717 5,617 7,731 Shared,
except
turbine hall
VII Contractor's
Engineering &
commissioning
19,302 20,074 15,966 22,197
VIII Contractor's Soft &
Miscellaneous Costs
(including Contractor's
insurance, contingencies,
margins and
preliminaries)
73,500 69,715 76,936 92,912
Transport Included Included Included Included
Gas compressors 13,487 14,831 11,597 Included
Adjust for OT C/W system 6,676 7,277 6,809 6,637 Shared
Jetty & unloading 7,972 8,690 8,130 7,925 Shared
Fuel tanks 18,933 21,700 22,814 24,952 Shared
Additional security
measures
2,418 2,635 2,886 2,403
Inlet filter adjustment
(spares)
0 82 150 86
Adjust for
civil/foundations
n/a n/a 5,530 n/a
EPC equivalent capital
cost excl. connections
469,658 447,395 488,448 463,378
21 Parameters for 2017-18 from WSP Parsons Brinkerhoff, op cit
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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=5.78%),
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)
13.2 SGDM real
(USD10M)
5.7
Total 8.7
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.
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The land cost is based on 12.5 Ha of land and 200m of water front for a two-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 $184 and $231 per square metre (the average has been applied). Water frontage
fees range from $1,004 to $1,507 per metre per year. Using the average annual cost at a discount
rate of 5.78% over 25 years, this gives an equivalent capital cost of $3.28 million. Total capital cost for
land assuming a mid-point land cost is thus $29.2 million (2 units).
Site preparation cost is relatively minor. For the current review, we have estimated this to be $2.03
million. Total land and site preparation costs are thus $31.2 million and a per-unit cost of SGD$15.6
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 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
920MW22
46
2 SPPG Engineering charge 2.4
3 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
30.86
4 Underground Cable (based on 3x 500MVA
circuits of 1 km length, direct burial)
Included in
Item 1
0
Total 79.3
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 SGD39.6M per unit.
22 Estimated output for 2 units at 24.7oC ambient
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Figure 11 Assumed electrical connection configuration (items per Table 18)
The gas connection costs are estimated to be 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 SGD93.8M, or SGD46.9M/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.
Jacobs 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
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Table 19 Owner's costs allowances (after financial closure)
Area Percentage of EPC +
connection cost
Cost, per unit (SGDM)
Owners Engineering 3% 15.31
Owners "minor items" 3% 15.31
Initial spares23 2% 10.21
Start-up costs 2% 10.21
Construction related insurance etc. 1% 5.10
Total 56.13
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
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
23 Note an additional adjustment for extra inlet filter spares is included above in Section 3.2
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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, Licences, fees 2% 10.21
Legal & financial advice
and costs
2% 10.21
Owner's engineering and
in-house costs
2% 10.21
Total 30.62
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.
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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 Jacobs has 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 6.039
Allowance for head office services 3.62
Fixed maintenance and other fixed operations24 16.68
Starts impact on turbine maintenance 1.24
Distillate usage impact on turbine maintenance 0.092
EMA Licence fee (fixed) 0.0592
Working capital (see below) 6.35
Emergency fuel usage 1.54
Property Tax 1.34
Insurance 4.63
Total (for 2 units) per year 41.60
Costs per unit would thus be SGD20.80M per year.
24 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
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36
Manning costs have been estimated based on 45 personnel covering 2 units at
SGD134,222/person/year. The unit rate considers the cost allowed in the 2015-16 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 Inflation. 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 index25
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 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.
25 Indexed produced using SingStats “Remuneration in manufacturing - Chemical and chemical products" change in average
remuneration per person year-to-year. Extrapolated in 2018 year.
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EOH costs are based on 2.50 USD/CCGT-MWh or 2.036 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 EUR694/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 619,137/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
45,953/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 18.75 SGD/GJ and
14.11 SGD/GJ for distillate and gas, respectively are applied.
This distillate cost assumption is based on USD592.33/t (USD79.51/bbl) for this report based on the
average of daily rates for Gasoil (10ppm) from January 2018 through March 2018. A handling and
delivery cost based on the allowance of USD6.31/bbl is added to give a delivered distillate cost of
USD85.82/bbl, or SGD18.75/GJ.
Working capital costs are the annual costs of the financial facilities needed to fund working capital.
This comprises two components:
• Emergency fuel inventory: 60 days (per 2 units), or 4.4PJ. 30 days must be stored on-site, and the
remaining 30 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 30 days will be
somewhere between zero and the working capital cost of the full extra 30 days inventory. Jacobs
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 30 + 30/2 days is allowed. This is allowed at the distillate cost of
SGD18.75/GJ and a pre-tax nominal WACC of 7.41% gives a working capital cost of
SGD6.00M/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 SGD4.71M and the working capital cost (using a pre-tax nominal
WACC of 7.41%) is SGD0.35M/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 (SGD18.76/GJ vs SGD14.11/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 cost26. Note is also made of the IRAS circular regarding
property taxes on plant and machinery27. 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
SGD267.8M (2 units).
26 Following http://www.business.gov.sg/EN/Government/TaxesNGST/TypesofTaxes/taxes_property.htm
27 IRAS circular: "TAX GUIDE ON NON-ASSESSABLE PLANT AND MACHINERY COMPONENTS FOR PETROCHEMICAL
AND POWER PLANTS", 16 Nov 2006.
DRAFT
38
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 2015-16 review
2017-18 review
2019-20 (current review)
Manning 5.37 5.39 6.04
Allowance for head office services 3.22 3.23 3.62
Fixed maintenance and other fixed
operations
16.11 17.87 16.68
Starts impact on turbine maintenance 1.04 1.17 1.24
Distillate usage impact on turbine
maintenance
0.078 0.09 0.09
EMA Licence fee (fixed) 0.058 0.058 0.059
Working capital 13.76 4.39 6.35
Emergency fuel usage 2.20 0.96 1.55
Property Tax 1.36 2.48 1.34
Insurance 4.47 4.88 4.63
Total (for 2 units) per year 47.67 40.52 41.60
4.2 Variable non-fuel cost (excluding carbon price)
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.
DRAFT
39
Table 23 Variable non fuel costs (excluding carbon price)
Area SGD/MWh Notes
Gas turbine & steam
turbine
5.619 Based on approximately EUR2.04/MWh of total plant ISO
output, adjusted for reference conditions and part load
factor
Steam turbine Incl.
Balance of plant,
chemicals,
consumables
0.50
Town Water 0.233 For a salt water cooled plant the town water costs are
typically small. Based on 0.1t/MWh usage and a cost of
2.33 SGD/t28.
EMC fees 0.302 EMC’s NEMS Budget for the Financial Year Ending 30 June
201929
PSO 0.272 PSO Budget projected 2018/1930
EMA Licence fee
(variable)
0.184
Total 7.111
Note the MWh in the above are those of the overall CCGT plant unit, not the individual turbine output.
A comparison with the values shown in the previous reviews is shown in Table 24.
Table 24 Variable operating cost allowance comparison, SGD/MWh
Area 2015-16 review
2017-18 review
2019-20 Current review
LTSA for Gas turbine 5.136 6.018 5.619
Steam turbine Incl. Incl. Incl.
Balance of plant, chemicals, consumables 0.55 0.557 0.50
Town Water 0.178 0.178 0.233
EMC fees 0.276 0.246 0.302
PSO 0.241 0.280 0.272
EMA Licence fee (variable) 0.179 0.179 0.184
Total 6.560 7.459 7.111
28 https://www.pub.gov.sg/watersupply/waterprice for “Non-domestic” NEWater + Water conservation tax + Waterborne fee
29 Appendix 2 of “EMC_Approved_Budget_for_FY1819_public_version”
30 Estimated PSO Fees ($/MWh) listed under FY2018/19 in “PSO budget and fees”
DRAFT
40
4.3 Carbon price
The Carbon Pricing Act 2018 has been enacted in Singapore which will result in a carbon price (tax)
being applied from 1 January 2019. The Carbon Tax Rate is a fixed rate in the third schedule of the
Act and is set at SGD5/tonne CO2-e. The carbon price covers the six greenhouse gases (GHGs) that
Singapore currently reports to the United Nations Framework Convention on Climate Change
(UNFCCC) as part of Singapore’s national GHG inventory.
The payment of the tax or surrendering of carbon credits must be made by the later of 30 September
of the year following the relevant year and 30 days after the service of a notice of assessment.
Jacobs assumes that the purchase of credits to settle the liability would be a tax deductible expense in
the Singapore tax system and hence that the carbon price acts as a regular operating expense in the
vesting contract procedures.
For transparency, and given that the carbon price in the Act does not escalate, other than as might be
provided for by subsequent legislation, Jacobs suggests that the carbon price component be shown as
a separate component of the LRMC.
EMA has advised that the IPCC factors 2006 Table 2.2 should be applied along with the Global
Warming Potentials listed in Schedule 1 of the Carbon Pricing Act. EMA has also advised that
distillate be given no weighting as distillate is separately taxed. The parameters for this assessment
are shown in Table 25.
Table 25 Carbon Emissions Factor, kg/GJ HHV
Area Weighting, and sum
CO2 CH4 N2O
Natural gas 99% 50.49 0.0189 0.0279
Distillate 0%
Weighted ∑ equals
50.03
49.99 0.02 0.03
The calculated GHG cost is shown in Table 26:
Table 26 Calculated impact of the carbon price
Area Value Units
Emissions factor 50.03 kg/GJ HHV
Heat rate 7.368 GJ/MWh HHV
Carbon price $5.00 $/tonne CO2-e
GHG cost $1.843 SGD/MWh
In the procedures, Jacobs recommend the GHG cost be incorporated by the addition of the following
rows (Table 27)
DRAFT
41
Table 27 Recommended amendments to the vesting contract procedures
No. (from
procedures)
Parameter Description Method of
Determination
Vesting
Contract
parameter/
Cell
Value
24a Carbon price
($Sing/tonne CO2-e)
Carbon price for
relevant entities
for emissions of
greenhouse gas
Carbon Pricing
Act 2018 -
Third Schedule
- Carbon Tax
Rate
CPrice $5.00
24b Carbon emissions
factor (tonnes CO2-e
/ GJ HHV)
Carbon
emissions factor
for the fuels
used by the
plant in Item 6,
Scope 1
Determined by
EMA (in
consultation
with the
engineering
and power
systems
experts)
CEF 50.03
DRAFT
42
5.1 Build duration
Current expected build duration for this type of plants is 30 months. This is unchanged from the
previous reviews.
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 25 years as discussed in Appendix B.
5.3 Average expected utilisation factor
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 63.42%.
5.4 Potential index for use in mid-term review
EMA propose to apply an index factor or factors to derive the parameters 7 and 8 (for capital costs) for
the mid-term review in 2019 to apply to the 2020 year.
In previous reviews Jacobs has noted that the capital cost parameters for item 7, the main plant
capex, have been uncertain due to volatility in the global market for CCGT plant construction.
At the present time the market for large CCGT plants is supressed due to oversupply of manufacturing
capability relative to world demand for such plants. There is no present indication that this situation
should change in the period prior to the time that the mid-term review would re-assess the costs, in
2019. Accordingly, Jacobs believes that it is reasonable to consider indexing the capital cost items
instead of re-assessing these in 2019.
Jacobs suggests that no indexation is applied to the main powerplant equipment (“Specialised
equipment” and “Other equipment” within the PEACE package, which comprises 48% of Item 7. The
balance of Item 7 is comprised of typical Singaporean construction activities. These could be
escalated using the Tender Price Index. The elements of Item 7 and the suggested indexation
method is shown in Table 28.
Table 28 Recommended indexation for Item 7 for the mid-term review
Parameter SGD k Weighting Suggested
index
I Specialized Equipment 195,515 41.45% None
II Other Equipment 28,923 6.13% None
III Civil 27,493 5.83% TPI
IV Mechanical 37,610 7.97% TPI
V Electrical Assembly & Wiring 8,995 1.91% TPI
5 OTHER PARAMETERS
DRAFT
43
Parameter SGD k Weighting Suggested
index
VI Buildings & Structures 7,731 1.64% TPI
VII Engineering & Plant Start-up 22,197 4.71% TPI
VIII Contractor's Soft & Miscellaneous Costs 92,912 19.70% TPI
Add gas compression 0 0.00% TPI
Adjust for OT C/W system 6,637 1.41% TPI
Jetty & unloading 7,925 1.68% TPI
Fuel tanks 24,952 5.29% TPI
Additional security measures 2,403 0.51% TPI
Additional spares beyond "standard" 86 0.02% TPI
Discounted through life capex 8,694 1.76% TPI
Item 7 total 472,072 100%
Item 8 is comprised of Land, Connections and owner’s costs before and after financial close. Land
costs should be escalated using the JTC Property Price Index. The Owner’s costs are based on
percentages of the other capital costs however the nature of these costs varies (labour, contingencies,
spares etc) and should be escalated with a general escalator such as MAS Core Inflation. Most of the
connection costs are based on the electricity connections which are a fixed value of $/MW and have
not escalated in several reviews. The balance of the connection costs have a general construction
nature and could be escalated at the Tender Price Index.
Escalators suggested for Item 8 suggested are thus as shown in Table 29:
Table 29 Recommended indexation for Item 8 for the mid-term review
Parameter SGD k Weighting Suggested
index
Land 15,623 10.5% JTC
Elec conns fixed) 24,211 16.2% None
Elec conns other 15,435 10.3% TPI
Gas conns 7,249 4.9% TPI
Owners cost 86,746 58.1% MAS Core
Total 149,264 100.0%
DRAFT
44
6.1 Introduction
The LRMC resulting from the inclusion of the parameters are considered in this report along with the
financial parameters that are determined in the financial parameters report or advised by EMA.
For the purposes of comparing the impacts of the changes in technical parameters, a calculation is
included in the LRMC, using assumptions for financial parameters where necessary.
6.2 Summary of technical parameters
Table 30 Summary of recommended technical parameters and previous values
Item Parameter 2015-2016 Review
2017-18 Review
2019-2020 Review
6 Economic capacity of the most economic
technology in operation in Singapore (MW)
386.67 407.92 427.86MW
net at
32oC
7 Capital cost of the plant identified in item 6
($US/kW)
936.79 890.68 836.74
USD/kW
8 Land, infrastructure and development cost of the
plant identified in item 6 ($Sing million)
151.27M 155.73 SGD
149.26M
11 HHV Heat Rate of the plant identified in item 6
(Btu/kWh)
7103.8 7108.7 6983.7
btu/kWh
net HHV
12 Build duration of the plant identified in item 6
(years)
2.5 2.5 2.5 years
13 Economic lifetime of the plant identified in item 6
(years)
24 25 25 years
14 Average expected utilisation factor of the plant
identified in item 6, i.e. average generation level as
a percentage of capacity (%)
64.4% 58.5 63.42%
15 Fixed annual running cost of the plant identified in
item 6 ($Sing)
23.83 M 20.26 20.80 M
SGD
16 Variable non-fuel cost of the plant identified in item
6 ($Sing/MWh)
6.56 7.46 7.11
SGD/MWh
24a Carbon price ($Sing/tonne CO2-e) 5 SGD/t
6 RESULTS – VESTING CONTRACT PARAMETERS
DRAFT
45
Item Parameter 2015-2016 Review
2017-18 Review
2019-2020 Review
24b Carbon emissions factor (tonnes CO2-e / GJ HHV) 50.03
kg/GJ
HHV
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
• Improved performance of “F” class CCGT configurations.
6.3 Calculated LRMC
Table 31 Assumed financial parameters for the LRMC calculation
Parameter Value Notes
WACC 6.15% post-tax, nominal
5.78% pre-tax, real
From financial parameters
report
CPI 1.54% Average year-on-year core
inflation, Jan 2018, Feb 2018,
Mar 2018.
Gas price $14.11 SGD/GJ Advised by EMA. Weighted
gas price (pipeline and LNG)
Exchange rates 1.32 SGD/USD
1.62 SGD/EUR
Average bid and ask, daily, Jan
2018, Feb 2018, Mar 2018.
Table 32 Calculated LRMC for 2019-20
Parameter Value SGD/MWh Notes
Fuel component 103.993
Capital component 24.68 See note below
Fixed opex 8.750
Variable opex 7.111
GHG cost 1.843
Total 146.37
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 33:
DRAFT
46
Table 33 Comparison of the calculated LRMC with the previous estimate, SGD/MWh
Parameter 2015-16 review 2017-18 review 2019-20 review
(Current review)
WACC 6.82% post-tax,
nominal
5.92% pre-tax, real
6.65% post-tax,
nominal
7.15% pre-tax, real
6.15% post-tax,
nominal
5.78% pre-tax, real
CPI 2.17% 0.80% 1.54%
Gas price $19.79 $9.87 $14.11 SGD/GJ
Exchange rates 1.2580 1.3643 1.319 SGD/USD
Fuel component 148.304 74.03 103.99 SGD/MWh
Capital component 28.76 31.14 24.68 SGD/MWh
Fixed opex 10.93 9.68 8.75 SGD/MWh
Variable opex 6.560 7.46 7.11 SGD/MWh
GHG component - - 1.843 SGD/MWh
Total 194.55 122.31 146.37 SGD/MWh
DRAFT
47
A PRESCRIBED PROCEDURES 48
B ECONOMIC LIFE 54
C THERMODYNAMIC ANALYSIS 55
APPENDICES
DRAFT
48
Table 34 Excerpt from Vesting Contract Procedures31
No. Parameter Description Method of
Determination
1 Determination Date Date on which the calculations of
the LRMC, which is to apply at
the Application Date, are deemed
to be made
Determined by EMA
2 Base Month Cut-off month for data used in
determination of the LRMC base
parameters.
For the following base
parameters which tend to be
volatile in nature, the data to be
used for estimating each of them
shall be based on averaging over
a three month leading up to and
including the Base Month:
• Exchange rate denominated in
foreign currencies into
Singapore dollars
• Diesel price to calculate cost
of carrying backup fuel
• Debt premium to calculate
cost of debt
• MAS Core inflation index
Determined by EMA
3 Application Date Period for which the LRMC to
apply
Determined by EMA
4 Current Year Year in which the Application
Date falls
Determined by EMA
5 Exchange Rate
($US per $Sing)
The exchange rate is that as
determined in Section 3.7
Determined by EMA (in
consultation with
finance experts)
31 Version 2.0, September 2013
A PRESCRIBED PROCEDURES
DRAFT
49
No. Parameter Description Method of
Determination
6 Economic capacity
of the most
economic
technology in
operation in
Singapore (MW)
The size of the most thermally
efficient unit taking into account
the requirements of the
Singapore system, including the
need to provide for contingency
reserve to cover the outage of the
unit and the fuel quantities
available. It is acknowledged that
this value may depend on the
manufacturer. (For CCGT
technology the size of the unit is
expected to be around 370MW)
Determined by EMA (in
consultation with the
engineering and power
systems experts)
7 Capital cost of the
plant identified in
item 6 ($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)
DRAFT
50
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
3.7.1
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
($Sing/GJ)
The current most economic
generating technology in
Singapore uses natural gas. This
is calculated using the weighted
average price of gas used for
commercial power generation,
determined by EMA in
accordance with Section 3.7.
Determined by EMA
DRAFT
51
No. Parameter Description Method of
Determination
10b LNG Price
($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)
DRAFT
52
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 ($Sing)
These costs are the fixed
operating and overhead costs
that are incurred in having the
plant available for supplying
energy and reserves but which
are not dependent on the quantity
of energy supplied. It is
acknowledged that some costs
are not easily classified as fixed
or variable. The costs expected
to be included in this parameter
are:
• Operating labour cost – it is
expected that the plant will be
running for three shifts per day
and seven days per week so
all operating labour cost is
likely to be a fixed annual cost
• Direct overhaul and
maintenance cost, with any
semi-variable costs treated as
annual fixed costs
• Generating Licence
• Insurance
• Property tax
• Costs of emergency fuel
• Other charges
• Other overhead costs
(a) Determined by
EMA, in consultation
with engineering and
power systems experts
in relation to the
following values:
• Operating labour
• Direct overhaul and
maintenance cost
• Costs of emergency
fuel
• Other overhead
costs; and
(b) Determined solely
by EMA
• Generating Licence
• Insurance
• Property tax
• Other charges
DRAFT
53
No. Parameter Description Method of
Determination
16 Variable non-fuel
cost of the plant
identified in item 6
($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. It is an estimate of the
industry standard ratio for private
sector generators in an economic
environment similar to Singapore
Determined by EMA (in
consultation with the
finance experts)
18 Risk free Rate (%) The risk-free rate in Singapore
shall be determined as the
average of the daily closing yield
on a default-free bond issued by
the local government
Determined by EMA (in
consultation with the
finance experts)
19 Cost of Debt (%) Risk-free rate plus a premium as
determined by the Authority.
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)
22 Tax rate (%) Corporate tax rate applicable to
generating companies in
Singapore at the base date.
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)
DRAFT
54
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 2018, and applying “E” class
CCGT’s in 1994 and the latest “F”/”H” class units in the 2018 Handbook32, the average improvement in
heat rate per year was assessed as -0.0067 GJ/MWh/y. The real rate of reduction in specific capital
cost was assessed as 1.1% 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 38.7 years. Thus, the economic
life of the new entrant plant is the lesser of this value and the technical life of the plant, which would be
approximately 30 years. This calculated economic life is sensitive to the gas price which has varied
over previous reviews. For consistency with the previous reviews a life of 25 years is recommended in
the analysis.
32 Jacobs expects that a new entrant would use “H” technology at this time
B ECONOMIC LIFE
DRAFT
55
Performance analysis of new entrant "F" class CCGT units has been undertaken using the GTPro and
GTMaster software suite Version 27. 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
DRAFT
56
Figure 13 Performance analysis - Ansaldo "F" class CCGT, clean-as-new, At Reference conditions
DRAFT
57
Figure 14 Performance analysis - GE "F" class CCGT, clean-as-new, At Reference conditions
DRAFT
58
Figure 15 Performance analysis - Mitsubishi "F" class CCGT, clean-as-new, At Reference conditions
DRAFT
59
Figure 16 Performance analysis - Siemens "F" class CCGT, clean-as-new, At Reference conditions
DRAFT
60
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Our deep industry knowledge together with skills in management consulting, technology and innovation allows us to challenge conventional thinking and deliver exceptional results with lasting impact.
Corporate headquarters
123 Buckingham Palace Road
London SW1W 9SR
United Kingdom
Tel: +44 20 7730 9000
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