ENERGY MARKET AUTHORITY Review of the Vesting Contract Technical Parameters for the period 1 January 2019 to 31 December 2020

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17 July 2018

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PA Regional Office:

PA Consulting Group

Level 13, Allied Nationwide Finance Tower,

142 Lambton Quay,

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New Zealand

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Version no: DRAFT 4.0

Prepared by: Rohan Zauner Document reference:

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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.

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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

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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

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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

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6.3 Calculated LRMC 45

APPENDICES 47

A PRESCRIBED PROCEDURES 48

B ECONOMIC LIFE 54

C THERMODYNAMIC ANALYSIS 55

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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

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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

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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

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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

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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

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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

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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

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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

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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

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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

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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

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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.

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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

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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

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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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20

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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26

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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27

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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29

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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31

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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© PA Knowledge Limited 2014.

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