Review of the Vesting Contract Technical Parameters for ... 2_Review of... · parameter values for...

ENERGY MARKET AUTHORITYReview of the Vesting Contract TechnicalParameters for the period 1 January 2019to 31 December 2020FINAL REPORT

13 November 2018

FINAL REPORT

PA Regional Office:PA Consulting GroupLevel 13, Allied Nationwide Finance Tower,142 Lambton Quay,Wellington 6011,New ZealandTel: +64 4 499 9053Fax: +64 4 473 1630www.paconsulting.com Version no: FINAL 11.0

Prepared by: Rohan Zauner Document reference:

http://www.paconsulting.com/

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This report is prepared for the EMA in connection with PA's review of the Vesting Contract priceparameters for 2019 and 2020. PA has prepared this report on the basis of information supplied by theEMA, data which is available in the public domain, and proprietary information. Whilst PA hasprepared this report with all due care and diligence and has no reason to doubt the documentation andinformation received, it has not independently verified the accuracy of the information and documentsprovided 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 ofthis report and its fitness for any particular purpose. Third parties reading and relying on the report doso 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 damagesarising 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 providerecommended values for the financial and technical parameters of the VestingContracts for electricity generation in Singapore for the period 2019 and 2020.Jacobs Group (Australia) Pty Ltd (Jacobs), formerly Sinclair Knight Merz (SKM), hasbeen engaged by PA Consulting to provide the technical parameters.

LRMC technical parametersThe following values are recommended by Jacobs for use in the Vesting Contract parameters for2019-20.

Table 1 Summary of recommended technical parameters

Item Parameter 2019-20 Value

6 Economic capacity of the most economictechnology in operation in Singapore (MW)

432.19 MW net at 32oC

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

922.84 USD/kW

8 Land, infrastructure and development cost of theplant identified in item 6 ($Sing million)

SGD 159.04M

11 HHV Heat Rate of the plant identified in item 6(Btu/kWh)

7006.1 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 plantidentified in item 6, i.e. average generation level asa percentage of capacity (%)

61.87%

15 Fixed annual running cost of the plant identified initem 6 ($Sing)

23.60 M SGD

16 Variable non-fuel cost of the plant identified in item6 ($Sing/MWh)

7.04 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 2LRMC technical parameters 2

1 INTRODUCTION 71.1 Financial parameters 7

1.2 Disclaimer 8

2 PERFORMANCE PARAMETERS 92.1 Existing generators 9

2.2 Generating technology 10

2.3 Capacity per generating unit 13

2.4 Impact of gas compression 16

2.5 Net capacity 19

2.6 Heat Rate 19

3 CAPITAL COST 243.1 Method 24

3.2 Initial capital cost 27

3.3 Through-life capital costs 29

3.4 Land and Site Preparation Cost 29

3.5 Connection Cost 30

3.6 Owner's costs after financial closure 31

3.7 Owner's costs prior to Financial Closure 32

4 OPERATING COSTS 344.1 Fixed annual running cost 34

4.2 Variable non-fuel cost (excluding carbon price) 37

4.3 Carbon price 39

5 OTHER PARAMETERS 415.1 Build duration 41

5.2 Economic life 41

5.3 Average expected utilisation factor 41

5.4 Potential index for use in mid-term review 41

6 RESULTS – VESTING CONTRACT PAR AMETERS 446.1 Introduction 44

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6.2 Summary of technical parameters 44

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

FIGURESFigure 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 gaspressure 17

Figure 5 Gas pressures in TUAS area 18

Figure 6 Impact of ambient temperature on heat rate 21

Figure 7 Variation of heat rate at part load 22

Figure 8 Trends in Singapore local construction cost parameters, 2014 = 100 26

Figure 9 BCA Tender Price Index, 2010 = 100 27

Figure 10 Assumed electrical connection configuration (items per Table 18) 31

Figure 11 Labour cost index 35

Figure 12 Performance analysis - Ansaldo "F" class CCGT, clean-as-new, At Referenceconditions 56

Figure 13 Performance analysis - GE "F" class CCGT, clean-as-new, At Reference conditions 57

Figure 14 Performance analysis - Mitsubishi "F" class CCGT, clean-as-new, At Referenceconditions 58

Figure 15 Performance analysis - Siemens "F" class CCGT, clean-as-new, At Referenceconditions 59

TABLESTable 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 14

Table 7 Variation in net power output with ambient temperature (relative to ReferenceConditions) 16

Table 8 Gas pressure trends, kPag 18

Table 9 Generation capacity of new entrant CCGT units (averaged over selected four gasturbine models) 19

https://www.singstat.gov.sg/-/media/files/news/cpimay2018.pdf

http://www.ema.gov.sg/Licensees_Electricity_Generation_Company.aspx

https://www.bca.gov.sg/keyconstructioninfo/others/free_stats.pdf

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

https://www.iras.gov.sg/IRASHome/uploadedFiles/IRASHome/e-Tax_Guides/etaxguides_PT_investors%20guide%20to%20property%20tax_2014-09-02.pdf

https://www.pub.gov.sg/watersupply/waterprice

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Table 10 Heat rate of new entrant CCGT units (clean-as-new at Reference Conditions includinggas 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 23

Table 14 Gas Turbine World Handbook budget plant prices for CCGT units, USD/kW ISO 25

Table 15 Local construction cost parameters (nominal) for Singapore 25

Table 16 EPC capital cost summary (per unit) for 2019-20, with comparison against earlierreviews 28

Table 17 Through-life capital expenditure (per unit) 29

Table 18 Electrical connection costs (2 units) 30

Table 19 Owner's costs allowances (after financial closure) 32

Table 20 Owner's costs allowances prior to Financial Closure 33

Table 21 Fixed annual operating cost allowance 34

Table 22 Fixed annual operating cost allowance comparison, SGD Millions for 2 units 37

Table 23 Variable non fuel costs (excluding carbon price) 38

Table 24 Variable operating cost allowance comparison, SGD/MWh 38

Table 25 Carbon Emissions Factor, kg/GJ HHV 39

Table 26 Calculated impact of the carbon price 39

Table 27 Recommended amendments to the vesting contract procedures 40

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 controlmarket power of generation companies in the National Electricity Market ofSingapore. The parameters for setting the Vesting Price associated with thesecontracts are to be reviewed every two years. The current review relates to thesetting 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 potentialfurther review if called for by EMA, and which would be the subject of a separatereport):

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 theVesting 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 theparameter values for items 7 and 8 for setting the vesting price for the 1-yearperiod, 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 Jacobsin the review of parameters for the period 1 January 2015 to 31 December 2016 (the“2015-16” review) and as subsequently modified in conjunction with EMA.

The parameters of the Vesting Contract determine the Vesting Price associated withthese contracts and are reviewed every two years, covering the subsequent two-yearperiod. The eighth of these two yearly reviews is the subject of this project, coveringthe period 1 January 2019 to 31 December 2020.

1.1 Financial parametersFinancial 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 7.13% post-tax, nominal

7.05% pre-tax, real

From financial parameters report

CPI 1.44% Average year-on-year core inflation,Mar 2018, Apr 2018, May 2018.Trend data is shown in Figure 1

Gas price $14.79 SGD/GJ Advised by EMA. Weighted gasprice (pipeline and LNG)

Exchange rates 1.32 SGD/USD

1.61 SGD/EUR

Average bid and ask, daily, Mar2018, Apr 2018, May 2018.

Figure 1 Singapore CPI data1

1.2 DisclaimerThis report has been prepared for the benefit of EMA for the purposes of setting the vesting contractprice for the 2019 to 2020 period. This report may not be relied upon by any other entity and may notbe relied upon for any other purpose.

1 Monthly data Department of Statistics, Singapore, https://www.singstat.gov.sg/-/media/files/news/cpimay2018.pdf and earliereditions

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

2.1 Existing generatorsParameters 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







SembCorp Cogen SKACCP1 392.5 2001 EMA/GE/004



Tuas Stage 2 CCP1 367.5 2001 EMA/GE/009



TUACCP4 367.5 2005 EMA/GE/009

TUACCP5 405.9 2014 EMA/GE/009

YTL PowerSeraya CCP1 368 2002 EMA/GE/016


2 http://www.ema.gov.sg/Licencees_Electricity_Generation_Company.aspx3 Combined Cycle Gas Turbine

2 PERFORMANCE PARAMETERS

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Large CCGT units Reg. Cap,MW

Date Licence



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

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

PacificLight Power Unit 1 400 2014 EMA/GE/005

PacificLight Power Unit 2 400 2014 EMA/GE/005

Tuaspring TSPBLK1 395.7 2016 EMA/GE/015

2.2 Generating technologyThe 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

Powerstation

Traincapacity

MWe

Numberof trains

Total stationFrame Fcapacity

MWe

CCGTtechnology

GT type OriginalEquipmentManufacturer(OEM)

SenokoConvertedCCGT

365 3 1095 Type F GT26 Alstom

Senokorepower(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

SerayaCCGT

368

364

370

370

4 1472 Type F V94.3A(SGT5-4000F)

Siemens

SembcorpCogen5

392.5 2 785 Type F 9FA GeneralElectric

SembcorpCogen

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 Jacobs5 Evaluations have been made based on CCGT performance only

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Powerstation

Traincapacity

MWe

Numberof trains

Total stationFrame Fcapacity

MWe

CCGTtechnology

GT type OriginalEquipmentManufacturer(OEM)

KeppelMerlimau

420 2 840 Type F GT26 Alstom

PacificLightPower

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 mitigatethe exercise of market power by the generation companies (“Gencos”). Vesting Contracts commit theGencos to sell a specified amount of electricity (viz the Vesting Contract level) at a specified price (vizthe Vesting Contract price). This removed the incentive for Gencos to exercise their market power bywithholding 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 thedecision was made in 2001 to implement Vesting Contracts.

And:

The Allocated Vesting Price approximates the Long Run Marginal Cost (LRMC) of a theoretical newentrant that uses the most economic generation technology in operation in Singapore and contributesto more than 25% of the total demand. …

The underlying concept of LRMC is to find the average price at which the most efficiently configuredgeneration facility with the most economic generation technology in operation in Singapore will coverits variable and fixed costs and provide reasonable return to investors. The plant to be used for thispurpose is to be based on a theoretical generation station with the most economic plant portfolio (forexisting CCGT technology, this consists of 2 to 4 units of 370MW plants). The profile of the mosteconomic 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 thattime.

– The generation company is assumed to operate as many of the units of the technologynecessary 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 ofscale.

– The plants are assumed to share common facilities such as land, buildings, fuel supplyconnections and transmission access. The cost of any common facilities should be proratedevenly 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 gasturbine technology (refer Table 4) which together comprise more than 50% of the generation capacityof Singapore. This is notwithstanding that Jacobs expect that a new entrant, if one were coming intothe 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 inSingapore 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 siteReference Conditions. For this review it is taken that the site Reference Conditions7 are the all-hoursaverage 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 includesoperation at the ambient conditions specified in the Singapore Market Manuals for the MaximumGeneration Capacity, which includes an ambient temperature of 32ºC. Consistent with the treatmentin 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, withoutcompetitive bidding for a specific local project, which design is the most economic generationtechnology on an LRMC basis for new built plant. It is often the case for example that theconfiguration offered with the lowest heat rate is the bid with a higher capital cost. In order to modelthe performance of the most economic generator it is therefore considered appropriate to consider theperformance of all these OEM's appropriate "F" class CCGT configurations and to use an arithmeticaverage of the performance parameters of each of these OEMs' plants in CCGT configuration.

In order to estimate these performance parameters, the GTPro/GTMaster10 (Version 28)thermodynamic analysis software suite was applied. Representative schematics of the resultingconfigurations are shown in Appendix C.

7 As applied in the 2015-16 review8 EMA has previously provided the average seawater temperature for TUAS area to be approximately 29.2 ºC9 Original Equipment Manufacturers10 TM, Thermoflow, Inc.

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2.3 Capacity per generating unitThe generation capacities of new entrant CCGT configurations, on a clean-as-new condition, and atthe Reference Conditions of 29.5ºC air temperature are given in Table 5. Note that upgrades of gasturbine technologies occur frequently, and judgement must be applied as to whether a new entrantdeveloper would choose the very latest announced version for a project in Singapore or not. In thisreview Jacobs has decided not to apply the very latest announced models of the GE gas turbine (the9F.0611) but to instead select the variants that have been available in the market for a longer time(considering commercial operating experience). Further, EMA has advised that the parameters of thelatest Mitsubishi “F” class unit, the M701F are considered sufficiently different to the other “F” classunits selected that the parameters of the earlier Mitsubishi unit, the M701F4, should be applied in thisanalysis. Jacobs has no objection to EMA’s assessment.

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 gasprice in Singapore favours selection of configurations with the best efficiency. These new designsoffer significantly higher capacity and efficiency than the units operating in Singapore at present andhigher 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 operationin Singapore and contributes to more than 25% of the total demand. In 2019-2020 “H” or “J” class gasturbines will not form 25% of total demand. Thus, it is interpreted that the procedure requiresevaluation 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 gascompression impacts)

Configuration Gross MW Net MW

Frame 9FB (nowdesignated 9F.05)

439.0 429.8

M701F4 457.1 448.0

GT26 499.3 486.0

SGT5-4000F 455.5 446.4

Average 462.7 452.6

This thermodynamic modelling includes all corrections necessary for:

· Ambient and sea water conditions of 29.2ºC;· Boiler blow-down; and· Step-up transformer losses.

No further allowances need to be made for these factors except as discussed below regardingambient temperature. The loads incorporated into GTPro are shown in Table 6.

11 Jacobs are not aware of any sales of this unit

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Table 6 Auxiliary loads incorporated within GTPro models, kW

SGT5-4000F

GT26 9F.05 701F4

GT fuel compressor(s) (at average gas pressure) 0 2697.5 53.7 0

GT supercharging fan(s) 0 0 0 0

GT electric chiller(s) 0 0 0 0

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

HRSG feedpump(s) 3106 3766 3266 2986.9

Condensate pump(s) 283.9 324.1 295.3 293.5

Cooling water pump(s) 1186.1 1389.8 1247.4 1231.7

Aux. from PEACE running motor/load list 1217 1506.5 1204 1317.2

Miscellaneous gas turbine auxiliaries 652.4 705.8 635.2 667.3

Miscellaneous steam cycle auxiliaries 81.73 97.37 86.21 81.24

Miscellaneous plant auxiliaries 227.7 249.6 219.5 228.6

Constant plant auxiliary load 0 0 0 0

Program estimated overall plant auxiliaries 6755 10736 7007 6806

Transformer losses 2277.3 2496.3 2195.1 2285.5

Total auxiliaries & transformer losses 9032.3 13232.3 9202.1 9091.5

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 timethe plant is clean-as-new12. The primary drivers for performance degradation are fouling, erosion androughening of the gas turbine compressor blades and material losses in the turbine section. A CCGTplant has a slightly reduced degradation profile than a simple cycle gas turbine installation due topartial recovery of the losses suffered by the gas turbine in the steam cycle, and that the gas turbineonly comprises approximately 2/3 of the plant output. This degradation effect is typically described ashaving two components:

"Recoverable" degradation is degradation of performance that occurs to the plant that can berecovered within the overhaul cycle. Recoverable degradation can be substantially remediated bycleaning or replacement of air inlet filters, water washing of the compressor, ball-cleaning ofcondensers and the like. These cleaning activities are typically undertaken several or many timeswithin a year depending on the site characteristics and the economic value of performance changes;and

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

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"Non-recoverable" degradation is caused by the impacts of temperature, erosion and corrosion ofparts within the plant. This type of degradation is typically substantially remediated at overhaul whendamaged parts are replaced with new or refurbished parts. Because the typical industry repairphilosophy uses an economic mix of new and refurbished parts within overhauls, it is typically the casethat 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, thedegradation 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 andintermediate loaded CCGT units are not considered to be materially affected by load factor or capacityfactor.

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% foraverage capacity degradation over the plant's life is suggested (calculated as a weighted averageusing 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 ofvariations in ambient temperature on the new entrant configurations and the average impact acrossthe four modelled configurations are shown in Table 7 and Figure 3.

13 Which is the estimated Available Capacity Factor for the plant

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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

701F4 102.2% 101.8% 101.4% 101.0% 100.6% 100.2% 99.8% 99.4% 99.0%

GT26 102.8% 102.3% 101.8% 101.3% 100.8% 100.3% 99.7% 99.2% 98.7%

9F05 103.9% 103.3% 102.6% 101.9% 101.1% 100.4% 99.6% 98.8% 97.9%

4000F 102.2% 101.9% 101.5% 101.1% 100.7% 100.2% 99.8% 99.2% 98.7%

Average 102.8% 102.3% 101.8% 101.3% 100.8% 100.3% 99.7% 99.2% 98.6%

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 areduction in capacity of 1.44% (averaged over the four models), or 6.53MW. Note that for variations ofambient relative humidity between 75% and 95% there is negligible difference in the performance ofCCGT plants with once-through cooling.

The electrical connection cost is based on the maximum net plant output, which is at an ambienttemperature of 24.7ºC. At this condition the average net output of the four OEMs’ plants is calculatedto be 463.5 MW/unit.

2.4 Impact of gas compressionGas compression is required for new entrant “F” class CCGT plants in Singapore.

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Three of the CCGT configurations noted (701F4, SGT5-4000F and 9F.05) use natural gas atapproximately 30 barg, and the GT26 uses natural gas at approximately 50 barg. The gascompressor power requirements calculated for the relevant gas turbines at varying network gaspressures are shown in Figure 4. An additional (approx.) 7 bar pressure drop allowance from thesystem pressure measurement point to the site boundary is included in the calculation.

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 fromJanuary 2017 onwards. The Network 1 pressure may be downstream of a regulator in which case theupstream pressure will be higher.

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Figure 5 Gas pressures in TUAS area

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 31 May) 3,882 3,882 3,385 3,808

The data indicates that gas compression is sometimes required under current conditions withminimum conditions rising after the commissioning of the LNG facility in 2013. Should the systempressures reduce (e.g. because of load growth) then gas compression would be required more often.

14 2014 to 2016 data from WSP Parsons Brinkerhoff report, op cit

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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 thatcompressors 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 relevantperiod, being the average pressure in the Network 2 in 2017 and 2018 of 38.5 Barg less anallowance 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 hasbeen included in the performance analysis of each of the gas turbines considered.

2.5 Net capacityThe resulting net capacity calculation after considering the above is shown in Table 9.

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) 462.7

Less parasitics = net capacity at Reference Conditions (clean-as-new) -10.1 = 452.6

Less allowance for gas compression Incl.

Adjust for 32ºC maximum registered capacity (-1.44%) -6.53

Adjust for average degradation (-3.06%) -13.9

Net capacity 432.2

2.6 Heat RateThe heat rates of new entrant CCGT configurations, on a clean-as-new condition, and at theReference 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

GT26 6.156 6.827 5.835 6.471

9F05 6.255 6.937 5.929 6.575

701F4 6.201 6.877 5.878 6.518

SGT5-4000F 6.120 6.787 5.801 6.433

Average 6.183 6.857 5.861 6.499

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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 regardingambient temperature.

As noted in Section 2.3 above, heat rates for CCGT plants are also subject to degradation. Aweighted average heat rate degradation over the plant's life of 1.90% is estimated (weighted by thepre-tax real discount factor for each year).

Variations in ambient temperature affect the heat rates of the generating units. The modelled impactsof variations in ambient temperature on the new entrant configurations and the average impact acrossthe four modelled configurations are shown in Table 11 and Figure 6.

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

701F4 100.1% 100.1% 100.1% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0%

GT26 100.0% 99.9% 100.0% 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% 100.1%

4000F 100.1% 100.1% 100.1% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0%

Average 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.1%

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Figure 6 Impact of ambient temperature on heat rate

Note that for variations of ambient relative humidity between 75% and 95% there is negligibledifference 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 theReference Conditions has been applied. It is not appropriate to consider the 32oC Standing CapabilityData criterion for capacity to also apply for the plant's heat rate except in as much as it impacts on theaverage part load factor as discussed below.

Whenever the power plant is operated at less than the Maximum Continuous Rating (MCR) of theplant at the relevant site conditions, the heat rate is affected. The modelled variation in heat rate withthe part load factor of the plant is shown in Table 12 and Figure 7

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

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

AverageHRrelative tofull load,

109.1% 107.4% 105.9% 104.7% 103.6% 102.6% 101.8% 101.0% 100.4% 99.8%

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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 61.87% 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 loadconditions, the calculated part load factor is 61.87% / 93.2% = 66.4%. The apparent part load factorfor the plant's performance is slightly reduced since the registered capacity would only be 98.5% of thenominal capacity. The resulting overall part load factor is 65.4% for which the part-load factor for heatrate would be 5.8%.

An additional adjustment is made to reflect the natural gas used in starts through the year. The gasusage 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 theheat rate (+0.5%). However, AGC requirement in Singapore is not considered to be materially differentfrom other jurisdictions, where minor perturbations of output on account of AGC (for those units in thesystem providing AGC service) or on droop-control are part of normal operations for which no specificextra allowance is considered appropriate. Note that the impact of operating the plant at part-load onaccount of the need for regulation and contingency reserve ancillary services is already accounted forwithin 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) - afterrecognition of parasitic loads

6.857 GJ/MWh HHV

Adjust for overall part load factor (+5.8%) +0.398

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 7.392 GJ/MWh HHV

Net HR 7,006 Btu/kWh HHV

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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 unloadingfacility and gas receiving facilities) classified under land and site preparation costin previous reviews,

· emergency fuel facilities classified under land and site preparation cost in previousreviews,

· civil works for the plans, erection and assembly, detailed engineering and start-upcosts, and contractor soft costs classified under connection cost in previousreviews and

· discounted through life capital cost classified under miscellaneous cost in previousreviews.

3.1 MethodThe capital cost of a new entrant CCGT plant using current costs is assessed using the PEACEsoftware which is part of the Thermoflow version 28 software suite.

Jacobs modelled the configurations noted in Section 2.3 above with the latest version of the PEACEsoftware using the current regional cost factors in-built into PEACE for Singapore. The evaluatedPEACE capital cost for the EPC equivalent cost of each configuration was then determined andaveraged across the four units applied15. Where some components (such as buildings) wereconsidered to be shared across a multiple-unit plant, the costs were assessed by modelling a two-unitplant with the costs shared between the two units.

The models include once through cooling, dual fuel installation, gas compression, and consideration ofthe 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 inPEACE by direct calculation or by escalating from the previous review.

15 In previous evaluations by Jacobs / SKM a market test was considered, with an adjustment to the PEACE price applied whereconsidered appropriate. EMA has advised that use of the PEACE price without such adjustment is preferred to make theresults as reproducible as possible. Jacobs has no objection to EMA’s assessment.

3 CAPITAL COST

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A comparison of data presented in recent editions of the Gas Turbine World Handbook for relevantgas turbines is shown in Table 14 for information. The various qualifications given in the Handbookshould be considered when evaluating this data.16. Jacobs considers that the Handbooks are not asdirectly useful as local market information and information from other projects because the Handbookinformation has a time-delay from the time it was written, it is not geographically specific and scopedifferences occur between editions of the Handbook.

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

Gas turbineunit for asingle shaftCCGT 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(M701F4)

533(M701F4)

560(M701F4)

670(M701F4)

659(M701F)17

659(M701F)17

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 CostIndex are not considered sufficiently reflective of the specific large-CCGT technology required forbasing the capital cost upon for this review.

The trends in a selection of local construction cost parameters for Singapore are shown in Table 15and Figure 8 for information.

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 99.9(May)

MAS Core Inflation 92.8 95.2 97.0 99.0 100.3 100.8 102.0 103.4 104.2(May)

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 previousyear)

-1% -1% -1% -1% 2% 2% 0% -2% -1%

16 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 ofprices for combined cycle plants depending on geographic location, site conditions, labour costs, OEM marketing strategies,currency valuations, order backlog and competitive situation.

17 There is no price listed in Volumes 32 or 33 for the M701F4 version18 Successive issues of Rawlinson’s “Australian Construction Cost Handbook”, International Construction Costs table (forinformation, not used in analysis), plus SingStats and BCA information for comparison

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2010 2011 2012 2013 2014 2015 2016 2017 2018

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. erectedSGD/t

5200 5280 5230 5200 5300 5300 5200 5100 4700

Figure 8 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 thecosts of key construction materials (concrete and structural steel) have fallen. The cost of acompleted industrial building has been static in nominal terms.

For minor capital cost elements of a civil/structural nature the costs in previous reviews have beenescalated from the values used earlier using the "All Buildings" Tender Price Index published by theBuilding and Construction Association (BCA) of Singapore19. This same treatment has been appliedin this review.

As shown in Figure 9, the Tender Price Index has fallen since Jacobs’ previous review, from 106.8 in2014 to 97.4 in (1st Q) 2018. The cost of the minor items of a construction nature is thus indexed innominal terms from the previous review by 91.2%. Items of a non-construction nature are escalatedusing the MAS Core index which has increased from the time of Jacobs’ previous review by 4.3%.

19 https://www.bca.gov.sg/keyconstructioninfo/others/free_stats.pdf

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Figure 9 BCA Tender Price Index, 2010 = 100

3.2 Initial capital costModifications are applied to make the unit cost applicable to this study to reflect different designfeatures for the Singapore plant, and to consider that the plant required for this review is based onshared infrastructure within a multi-unit plant. A two-unit plant is assumed. The modifications appliedare:

· 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;· Adjustment for additional civil/foundation costs considered appropriate for the location of the site;

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 SGD520,670M per unit asshown 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 2013-14review

SGD k

2015-16review

SGD k

2017-18review21

SGD k

2019-20review

SGD k

Comments

I Specialized Equipment 240,505 214,780 242,377 219,495

II Other Equipment 11,306 11,389 11,489 30,86622

III Civil 24,925 25,802 31,771 30,352 Shared

IV Mechanical 35,081 33,580 37,470 41,297

V Electrical Assembly &Wiring

5,099 7,123 8,905 9,875

VI Buildings &Structures

10,455 9,717 5,617 8,572 Shared,exceptturbine hall

VII Contractor'sEngineering &commissioning

19,302 20,074 15,966 26,545

VIII Contractor's Soft &Miscellaneous Costs(including Contractor'sinsurance, contingencies,margins andpreliminaries)

73,500 69,715 76,936 103,124

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 27,128 Shared

Additional securitymeasures

2,418 2,635 2,886 3,025

Inlet filter adjustment(spares)

0 82 150 154

Adjust forcivil/foundations

n/a n/a 5,530 5,675

EPC equivalent capitalcost excl. connections

469,658 447,395 488,448 520,670

21 Parameters for 2017-18 from WSP Parsons Brinkerhoff, op cit22 Now incl. gas compressors

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Note that there may be additional savings if both units of a two unit plant were procured at the sametime. A small reduction in the costs of the second (and subsequent units if more than two areprocured) which is expected to be of the order of 5% would result due to the sharing of transaction andengineering costs at both the contractor and owner level. Where the plant procurement is phased bymore 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 ofoutput lost when one gas turbine trips). The specific capital cost (SGD/MW) can be materially lowerwith a "2+1" arrangement than for two "1+1" blocks. However, this depends on the load net growthbeing sufficiently high to justify the additional capacity being constructed immediately after the firstunit. This is not included in this analysis.

3.3 Through-life capital costsCapital costs of plant maintenance through the overhaul cycle of the gas turbine and steam turbine areincluded in Sections 4.1 and 4.2.

Additional capital costs are incurred through the project's life. Actual costs incurred vary considerablyand 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 Discountedequivalent,

SGDM/unit (pre-taxreal WACC=7.05%),

per unit

Distributed controlsystem (DCS)

15 years 7 SGDM real 2.5

Gas turbine rotor 15 years (100,000 to150,000 operating

hours)

13.2 SGDM real(USD10M)

4.8

Total 7.3

The cost of the DCS upgrade depends on the level of obsolescence of related items such as fieldinstrumentation and associated wiring.

Towards the end of the notional technical life of the plant, if market studies indicated that the plantmay still be economic, studies would be undertaken to evaluate extending the plant's life. The studiesand the resulting costs and resulting life extensions are not included.

3.4 Land and Site Preparation CostThe 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 gasreceiving facilities) and (ii) emergency fuel facilities. These costs have been included under capitalcost 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 datapublished by the JTC Corporation’s Land Rents and Prices, for a 30-year lease, the land price at TuasView is between $184 and $231 per square metre (the average has been applied). Water frontagefees range from $1,004 to $1,507 per metre per year. Using the average annual cost at a discountrate of 7.05% over 25 years, this gives an equivalent capital cost of $2.91 million. Total capital cost forland assuming a mid-point land cost is thus $28.9 million (2 units).

Site preparation cost is relatively minor. For the current review, we have estimated this to be $2.03million. Total land and site preparation costs are thus $30.9 million and a per-unit cost of SGD$15.4million.

3.5 Connection CostConnection costs exclude civil works for the plant’s, erection and assembly, detailed engineering andstart-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 Table18. Jacobs has taken into consideration in this assessment the cost of connecting two 400MW CCGTunits using the configuration shown in Figure 10. Depending on the cut-in arrangement, it isanticipated 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 usedthe 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) SGD50,000/MW x

927MW23

46.4

2 SPPG Engineering charge 2.4

3 230kV Switchgear GISNotes:

Includes switch house but excludes gentransformer which is included with thepower plant cost

GIS completediameters @breaker and a

halfconfiguration

+ 2/3 diameter

30.86

4 Underground Cable (based on 3x 500MVAcircuits of 1 km length, direct burial)

Included inItem 1

0

Total 79.7

Based on the standard Power Grid connection charge, the cost of electrical connection including thecost of the typical 230kV switchgear is thus estimated to be SGD39.8M per unit.

23 Estimated output for 2 units at 24.7oC ambient

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Figure 10 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 shortdistances in the TUAS View area, a 400mm connection would be readily able to cope with the gasrequirements of two units, including at 24.7ºC ambient, and with relative low velocities and pressuredrop.

Total connection cost is thus SGD94.2M, or SGD47.1M/unit.

3.6 Owner's costs after financial closureThe Owner's costs incurred from Financial Closure to the Commercial Operation Date of the plant aretypically 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 perMW

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% 17.03

Owners "minor items" 3% 17.03

Initial spares24 2% 11.35

Start-up costs 2% 11.35

Construction related insurance etc. 1% 5.68

Total 62.45

Note that the capital cost estimates are made at the 50th percentile of expected outcomes as isconsidered appropriate for this application. The EPC estimate includes the contingency and riskallowances, along with profit margins, normally included in the Contractor's EPC cost estimates. Theextra contingency allowances normally included by the owner within investment decision makingprocesses 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 andmanagement services after financial closure, including inspections and monitoring of the works,contract administration and superintendancy, project management and coordination between the EPCcontractor, connection contractors and contractors providing minor services, witnessing of tests andmanagement reporting.

Minor items include all the procurement costs to the owner outside of the primary plant EPC costs andthe 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 specificoptimisation or cost requirements of the plant above those of a "generic" standard plant covered inSection 3.2.

Start-up costs include the cost to the owner of bringing the plant to commercial operation (noting thatthe actual commissioning of the plant is within the plant EPC contractor's scope). The owner istypically responsible for fuels and consumables used during testing and commissioning, recruiting,training and holding staff prior to operations commencing, and for establishing systems andprocedures.

Note that initial working capital, including initial working capital for liquid fuel inventory and foraccounts receivable versus payable, are not included (these are an ongoing finance charge includedin the fixed operating costs of the plant in Section 4.1).

3.7 Owner's costs prior to Financial ClosureAt the time of Financial Closure, when the investment decision is being made, the costs accrued up tothat time against the project are "sunk" and are sometimes not included in a new entrant costestimate.

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

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Nevertheless, the industry needs to fund the process of developing projects to bring a plant from initialconception up to financial closure. If these are to be added, the costs can be highly variable. Theallowances should include both in-house and external costs to the owner/developer from conceptonwards 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 periodleading up to financial close. An example of typical allowances based on percentages of the EPC costis shown in Table 20.

Table 20 Owner's costs allowances prior to Financial Closure

Area Percentageof EPC +

connectioncost

Cost, per unit(SGDM)

Permits, Licences, fees 2% 11.35

Legal & financial adviceand costs

2% 11.35

Owner's engineering andin-house costs

2% 11.35

Total 34.06

Permits, licences and fees primarily consist of gaining the environmental and planning consents forthe 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, managementapprovals and due diligence processes.

Owner's engineering and in-house costs prior to financial closure include the costs of conceptual andpreliminary designs and studies (such as optimisation studies), specifying the plant, tendering andnegotiating the EPC plant contract, negotiating connection agreements, attending on the feasibilityassessment and due diligence processes, management reporting and business case preparation, etc.

Project development on a project financed basis sometimes incurs extra transaction costs, such asswaptions for foreign exchange cover or for forward interest rate cover. These are highly projectspecific and not always necessary. No extra allowance is included.

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4.1 Fixed annual running costAn 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 substantiallyas variable costs. The EMA Vesting Contract Procedures state that semi-variable maintenance costsshould be included with the fixed costs amounts. If calculated correctly with the appropriate plantfactor, the same vesting contract LRMC will result. Current LTSA costs for CCGT plants have beenexpressed as variable costs in this review and hence these costs are included in the variable costsection.

Typically, an LTSA only covers the main gas turbine and steam turbine components. All of thebalance of the plant including boilers, cooling system, electrical plant is maintained separately by theowner outside of the LTSA. The cost of this maintenance is typically considered to be a fixed cost andis included in this section.

Table 21 Fixed annual operating cost allowance

Area SGDM for 2 units

Manning 6.04

Allowance for head office services 3.62

Fixed maintenance and other fixed operations25 18.74

Additional cyber security maintenance 0.283

Starts impact on turbine maintenance 1.19

Distillate usage impact on turbine maintenance 0.088

EMA Licence fee (fixed) 0.062

Working capital (see below) 7.71

Emergency fuel usage 1.67

Property Tax 2.59

Insurance 5.21

Total (for 2 units) per year 47.21

Costs per unit would thus be SGD23.60M per year.

25 Calculated as 3% of the plant capital cost per year excluding the cost attributable to the gas turbine and steam turbine (whichare included in the variable operating/maintenance costs below). These costs need to cover non-turbine maintenance, all otherfixed costs including fixed charges of utilities and connections, service contracts, community service obligations etc.

4 OPERATING COSTS

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Manning costs have been estimated based on 45 personnel covering 2 units atSGD134,222/person/year. The unit rate considers the cost allowed in the 2015-16 review indexedusing a factor produced from average remuneration changes in a “chemicals” manufacturingenvironment in Singapore (in the absence of a power generation industry index being available) andMAS Core Inflation. The index used is shown in Figure 11.

The personnel include shift operators/technicians and shift supervision as well as day shiftmanagement, 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 andindirect costs.

Figure 11 Labour cost index26

Head office costs would be highly variable and depend on the structure of the business and the otheractivities the business engages in. Only head office support directly associated with power generationshould be included as part of head office costs. The allowance for head office costs is a nominalallowance (60% of manning cost allowance) for services that might be provided by head-office that arerelevant 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'sadd an Equivalent Operating hours (EOH) factor for starts and this impacts on the costs under theLTSA.

26 Index produced using SingStats “Remuneration in manufacturing - Chemical and chemical products" change in averageremuneration per person year-to-year. Extrapolated in 2018 year.

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EOH costs are based on 2.50 USD/CCGT-MWh or 2.06 EUR/CCGT-MWh at nominal ISO full loadbased on discussions with the OEMs. Allowing for the correction from ISO to reference conditions theequivalent cost is EUR704/GT-EOH. The EOH factor is also increased by the part-load factor sincethe EOH measurement is based on operating hours rather than MWh. Note that the LTSA is based onthe gas and steam turbine only rather than maintenance of the whole plant. The starts factor onlyimpacts on the gas turbine component however. Based on 55 starts/unit and 10 EOH/start, the cost isSGD 594,063/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 naturalgas fuel operation is 0.5 EOH/hour. This equates to an impact on maintenance of SGD44,092/unit/year.

Calculation of the working capital cost and the emergency fuel usage cost below requires an estimateof the costs of distillate and natural gas. For the purposes of this report prices of 19.89 SGD/GJ and14.79 SGD/GJ for distillate and gas, respectively are applied.

This distillate cost assumption is based on USD628.74/t (USD84.39/bbl) for this report based on theaverage of daily rates for Gasoil (10ppm) from March 2018 through May 2018. A handling anddelivery cost based on the allowance of USD6.26/bbl is added to give a delivered distillate cost ofUSD90.65/bbl, or SGD19.89/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 4.3PJ. 30 days must be stored on-site, and theremaining 30 days may be stored by the fuel vendor in Singapore provided that it can be securelydelivered to the power station when required. The working capital cost of the extra 30 days will besomewhere between zero and the working capital cost of the full extra 30 days inventory. Jacobsare unable to ascertain where in this range the cost that would be charged by the supplier wouldbe. For the purposes of this report, we have allowed for a midrange estimate of 50%. That is, aneffective working capital cost of 30 + 30/2 days is allowed. This is allowed at the distillate cost ofSGD19.89/GJ and a pre-tax nominal WACC of 8.59% gives a working capital cost ofSGD7.29M/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 settlementperiod in the market of 20 days from the time of generation). For two units the working capitalrequirement on this basis is SGD4.81M and the working capital cost (using a pre-tax nominalWACC of 8.59%) is SGD0.41M/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 distillateover natural gas (SGD19.89/GJ vs SGD14.79/GJ).

Property tax has been estimated based on 10% per year of an assumed Annual Value of 6% of theland, preparation and buildings/structures cost27. The Annual Value also includes allowances forRepairs and Maintenance, Insurance and Property Tax itself28. Note is also made of the IRAS circularregarding property taxes on plant and machinery29. The value of certain fixed plant and machineryitems must be included within the property valuation when calculating property taxes. However, anappended list of exemptions exempts most of the principal plant items of a CCGT plant includingturbines, generators, boilers, transformers, switchgear etc. To allow for the extra value of the portion

27 Following http://www.business.gov.sg/EN/Government/TaxesNGST/TypesofTaxes/taxes_property.htm28 https://www.iras.gov.sg/IRASHome/uploadedFiles/IRASHome/e-Tax_Guides/etaxguides_PT_investors%20guide%20to%20property%20tax_2014-09-02.pdf

29 IRAS circular: "TAX GUIDE ON NON-ASSESSABLE PLANT AND MACHINERY COMPONENTS FOR PETROCHEMICALAND POWER PLANTS", 16 Nov 2006.

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of the plant that is included, 10% of the cost of the plant is included in the property tax valuationcalculation (except where already included). The total value included for calculation of property tax isthus SGD289.5M (2 units) and the Annual Value is $25.91M.

Insurance has been estimated based on 0.5% of the capital cost. This is considered to coverproperty, plant and industrial risks but would not cover business interruption insurance or the cost ofhedging 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 2015-16review

2017-18review

2019-20(currentreview)

Manning 5.37 5.39 6.04

Allowance for head office services 3.22 3.23 3.62

Fixed maintenance and other fixedoperations

16.11 17.87 18.74

Additional cyber security maintenance - 0.283

Starts impact on turbine maintenance 1.04 1.17 1.19

Distillate usage impact on turbinemaintenance

0.078 0.09 0.09

EMA Licence fee (fixed) 0.058 0.058 0.062

Working capital 13.76 4.39 7.71

Emergency fuel usage 2.20 0.96 1.67

Property Tax 1.36 2.48 2.59

Insurance 4.47 4.88 5.21

Total (for 2 units) per year 47.67 40.52 47.21

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

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Table 23 Variable non fuel costs (excluding carbon price)

Area SGD/MWh Notes

Gas turbine & steamturbine

5.472 Based on approximately EUR2.06/MWh of total plant ISOoutput, adjusted for reference conditions and part loadfactor

Steam turbine Incl.

Balance of plant,chemicals,consumables

0.574

Town Water 0.233 For a salt water cooled plant the town water costs aretypically small. Based on 0.1t/MWh usage and a cost of2.33 SGD/t30.

EMC fees 0.302 EMC’s NEMS Budget for the Financial Year Ending 30 June201931

PSO 0.272 PSO Budget projected 2018/1932

EMA Licence fee(variable)

0.191

Total 7.043

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 2015-16review

2017-18review

2019-20Currentreview

LTSA for Gas turbine 5.136 6.018 5.472

Steam turbine Incl. Incl. Incl.

Balance of plant, chemicals, consumables 0.55 0.557 0.574

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 0.191

Total 6.560 7.459 7.043

30 https://www.pub.gov.sg/watersupply/waterprice for “Non-domestic” NEWater + Water conservation tax + Waterborne fee31 Appendix 2 of “EMC_Approved_Budget_for_FY1819_public_version”32 Estimated PSO Fees ($/MWh) listed under FY2018/19 in “PSO budget and fees”

FINAL REPORT

39

4.3 Carbon priceThe 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 theAct and is set at SGD5/tonne CO2-e. The carbon price covers the six greenhouse gases (GHGs) thatSingapore 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 Septemberof 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 inthe Singapore tax system and hence that the carbon price acts as a regular operating expense in thevesting contract procedures.

For transparency, and given that the carbon price in the Act does not escalate, other than as might beprovided for by subsequent legislation, Jacobs suggests that the carbon price component be shown asa separate component of the LRMC.

EMA has advised that the IPCC factors 2006 Table 2.2 should be applied along with the GlobalWarming Potentials listed in Schedule 1 of the Carbon Pricing Act. EMA has also advised thatdistillate be given no weighting as distillate is separately taxed. The parameters for this assessmentare 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 ∑ equals50.03

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 7.391 GJ/MWh HHV

Carbon price $5.00 $/tonne CO2-e

GHG cost $1.849 SGD/MWh

In the procedures, Jacobs recommend the GHG cost be incorporated by the addition of the followingrows (Table 27).

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Table 27 Recommended amendments to the vesting contract procedures

No. (fromprocedures)

Parameter Description Method ofDetermination

VestingContractparameter/Cell

Value

24a Carbon price($Sing/tonne CO2-e)

Carbon price forrelevant entitiesfor emissions ofgreenhouse gas

Carbon PricingAct 2018 -Third Schedule- Carbon TaxRate

CPrice $5.00

24b Carbon emissionsfactor (tonnes CO2-e

/ GJ HHV)

Carbonemissions factorfor the fuelsused by theplant in Item 6,Scope 1

Determined byEMA (inconsultationwith theengineeringand powersystemsexperts)

CEF 50.03

FINAL REPORT

41

5.1 Build durationCurrent expected build duration for this type of plants is 30 months. This is unchanged from theprevious reviews.

5.2 Economic lifeThe 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 factorEMA has advised that for consistency with the previous reviews, the actual historic capacity factor forthe previous 12 months should again be applied. This value has been advised by EMA to be 61.87%.

5.4 Potential index for use in mid-term reviewEMA propose to apply an index factor or factors to derive the parameters 7 and 8 (for capital costs) forthe 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 plantcapex, 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 manufacturingcapability relative to world demand for such plants. There is no present indication that this situationshould change in the period prior to the time that the mid-term review would re-assess the costs, in2019. Accordingly, Jacobs believes that it is reasonable to consider indexing the capital cost itemsinstead of re-assessing these in 2019.

Jacobs suggests that no indexation is applied to the main powerplant equipment (“Specialisedequipment” and “Other equipment” within the PEACE package, which comprises 48% of Item 7. Thebalance of Item 7 is comprised of typical Singaporean construction activities. These could beescalated using the Tender Price Index. The elements of Item 7 and the suggested indexationmethod is shown in Table 28.

5 OTHER PARAMETERS

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Table 28 Recommended indexation for Item 7 for the mid-term review

Parameter SGD k Weighting Suggestedindex

I Specialized Equipment 219,495 41.57% None

II Other Equipment 30,866 5.85% None

III Civil 30,352 5.75% TPI

IV Mechanical 41,297 7.82% TPI

V Electrical Assembly & Wiring 9,875 1.87% TPI

VI Buildings & Structures 8,572 1.62% TPI

VII Engineering & Plant Start-up 26,545 5.03% TPI

VIII Contractor's Soft & Miscellaneous Costs 103,124 19.53% TPI

Add gas compression 0 0.00% TPI

Adjust for OT C/W system 6,637 1.26% TPI

Jetty & unloading 7,925 1.50% TPI

Fuel tanks 27,128 5.14% TPI

Additional security measures 3,025 0.57% TPI

Additional spares beyond "standard" 154 0.03% TPI

Adjustment for civils/foundations 5,675 1.07% TPI

Discounted through life capex 7,287 1.38% TPI

Item 7 total 527,957 100%

Item 8 is comprised of Land, Connections and owner’s costs before and after financial close. Landcosts should be escalated using the JTC Property Price Index. The Owner’s costs are based onpercentages 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 theconnection costs are based on the electricity connections which are a fixed value of $/MW and havenot escalated in several reviews. The balance of the connection costs have a general constructionnature and could be escalated at the Tender Price Index.

Escalators suggested for Item 8 suggested are thus as shown in Table 29:

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Table 29 Recommended indexation for Item 8 for the mid-term review

Parameter SGD k Weighting Suggestedindex

Land 15,440 9.7% JTC

Elec conns (fixed) 24,395 15.3% None

Elec conns (other) 15,435 9.7% TPI

Gas conns 7,249 4.6% TPI

Owners cost 96,517 60.7% MAS Core

Total 159,037 100.0%

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6.1 IntroductionThe LRMC resulting from the inclusion of the parameters are considered in this report along with thefinancial 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 isincluded in the LRMC, using assumptions for financial parameters where necessary.

6.2 Summary of technical parametersTable 30 Summary of recommended technical parameters and previous values

Item Parameter 2015-2016Review

2017-18Review

2019-2020Review

6 Economic capacity of the most economictechnology in operation in Singapore (MW)

386.67 407.92 432.19MWnet at32oC

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

936.79 890.68 922.84USD/kW

8 Land, infrastructure and development cost of theplant identified in item 6 ($Sing million)

151.27M 155.73 SGD159.04M

11 HHV Heat Rate of the plant identified in item 6(Btu/kWh)

7103.8 7108.7 7006.1btu/kWhnet 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 plantidentified in item 6, i.e. average generation level asa percentage of capacity (%)

64.4% 58.5 61.87%

15 Fixed annual running cost of the plant identified initem 6 ($Sing)

23.83 M 20.26 23.60 MSGD

16 Variable non-fuel cost of the plant identified in item6 ($Sing/MWh)

6.56 7.46 7.04SGD/MWh

24a Carbon price ($Sing/tonne CO2-e) 5 SGD/t

6 RESULTS – VESTING CONTRACT PAR AMETERS

FINAL REPORT

45

Item Parameter 2015-2016Review

2017-18Review

2019-2020Review

24b Carbon emissions factor (tonnes CO2-e / GJ HHV) 50.03kg/GJHHV

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

· The method incorporates the current Thermoflow PEACE costs without market adjustment, and theuse of the latest version of the Thermoflow software (version 28); and

· Improved performance of “F” class CCGT configurations.

6.3 Calculated LRMCTable 31 Assumed financial parameters for the LRMC calculation

Parameter Value Notes

WACC 7.13% post-tax, nominal

7.05% pre-tax, real

From financial parametersreport

CPI 1.44% Average year-on-year coreinflation, Mar 2018, Apr 2018,May 2018.

Gas price $14.79 SGD/GJ Advised by EMA. Weightedgas price (pipeline and LNG)

Exchange rates 1.32 SGD/USD

1.61 SGD/EUR

Average bid and ask, daily,Mar 2018, Apr 2018, May2018.

Table 32 Calculated LRMC for 2019-20

Parameter Value SGD/MWh Notes

Fuel component 109.32

Capital component 30.94 See note below

Fixed opex 10.08

Variable opex 7.04

GHG cost 1.85

Total 159.22

Note that in accordance with the Vesting Contract formulae and the treatment in previous years, theWACC applied in the calculation of the LRMC is the nominal WACC. Comparisons with previousestimates are shown in Table 33:

FINAL REPORT

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

7.13% post-tax,nominal

7.05% pre-tax, real

CPI 2.17% 0.80% 1.44%

Gas price $19.79 $9.87 $14.79 SGD/GJ

Exchange rates 1.2580 1.3643 1.324 SGD/USD

Fuel component 148.304 74.03 109.32 SGD/MWh

Capital component 28.76 31.14 30.94 SGD/MWh

Fixed opex 10.93 9.68 10.08 SGD/MWh

Variable opex 6.560 7.46 7.04 SGD/MWh

GHG component - - 1.85 SGD/MWh

Total 194.55 122.31 159.22 SGD/MWh

FINAL REPORT

47

A PRESCRIBED PROCEDURES 48

B ECONOMIC LIFE 54

C THERMODYNAMIC ANALYSIS 55

APPENDICES

FINAL REPORT

48

Table 34 Excerpt from Vesting Contract Procedures33

No. Parameter Description Method ofDetermination

1 Determination Date Date on which the calculations ofthe LRMC, which is to apply atthe Application Date, are deemedto be made

Determined by EMA

2 Base Month Cut-off month for data used indetermination of the LRMC baseparameters.

For the following baseparameters which tend to bevolatile in nature, the data to beused for estimating each of themshall be based on averaging overa three month leading up to andincluding the Base Month:

· Exchange rate denominated inforeign currencies intoSingapore dollars

· Diesel price to calculate costof carrying backup fuel

· Debt premium to calculatecost of debt

· MAS Core inflation index

Determined by EMA

3 Application Date Period for which the LRMC toapply

Determined by EMA

4 Current Year Year in which the ApplicationDate falls

Determined by EMA

5 Exchange Rate

($US per $Sing)

The exchange rate is that asdetermined in Section 3.7

Determined by EMA (inconsultation withfinance experts)

33 Version 2.0, September 2013

A PRESCRIBED PROCEDURES

FINAL REPORT

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6 Economic capacityof the mosteconomictechnology inoperation inSingapore (MW)

The size of the most thermallyefficient unit taking into accountthe requirements of theSingapore system, including theneed to provide for contingencyreserve to cover the outage of theunit and the fuel quantitiesavailable. It is acknowledged thatthis value may depend on themanufacturer. (For CCGTtechnology the size of the unit isexpected to be around 370MW)

Determined by EMA (inconsultation with theengineering and powersystems experts)

7 Capital cost of theplant identified initem 6 ($US/kW)

Capital cost includes thepurchase and delivery cost of theplant in a state suitable forinstallation in Singapore and allassociated equipment butexcludes switchgears, fuel tanks,transmission and fuelconnections, land, buildings andsite development included in item8. Where more than one unit isexpected to be installed that willshare any equipment, the costsof the shared equipment shouldbe prorated evenly to each of theunits

Determined by EMA(and in consultationwith the engineeringand power systemsexperts)

FINAL REPORT

50


8 Land, infrastructureand developmentcost of the plantidentified in item 6($Sing million)

Where more than one unit isexpected to be installed that willshare any equipment or facilities,the costs of the sharedequipment or facilities should beprorated evenly to each of theunits. These costs shouldinclude all capital, developmentand installation costs (excludingall costs included in item 7 andfinancing costs during the buildperiod). These costs shouldinclude the following specificitems:

· Acquisition costs of sufficientland to accommodate theplant defined above in item 6(alternatively land may beincluded as annual rental costunder Fixed Annual RunningCosts)

· 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 withthe engineering andpower systems expertsin relation to thefollowing values:

· size of site required· site development· buildings and

facilities· connections to

pipelines· switchgear

connections totransmission

· emergency fuelfacilities

· projectmanagement andconsultancy; and

(b) In consultation withreal estate experts inrelation to land value

9a HSFO 180 CST OilPrice (US$/MT)

The HSFO 180 CST Oil Price isthat as determined in Section3.7.1

Determined by EMA

9b Brent Index Price The Brent Index is that asdetermined in Section 3.7.2

Determined by EMA

10a Gas Price

($Sing/GJ)

The current most economicgenerating technology inSingapore uses natural gas. Thisis calculated using the weightedaverage price of gas used forcommercial power generation,determined by EMA inaccordance with Section 3.7.

Determined by EMA

FINAL REPORT

51


10b LNG Price

($Sing/GJ)

This is the Singapore regasifiedLNG price as determined by theAuthority. The LNG price is usedin place of 10a for the LNGVesting Quantities under the LNGVesting Scheme.

The LNG Price includes:

· the LNG hydrocarbon charge· any fees or charges imposed

by the Authority on theimported gas

· the LNG terminal tariff· the average gas pipeline

transportation tariff applicableto regasified LNG

· the LNG Aggregator’s margin· the cost of Lost and

Unaccounted For Gas (LUFG)

Determined by EMA

11 HHV Heat Rate ofthe plant identifiedin item 6 (Btu/kWh)

The high heat value heat rate ofthe plant specified under item 6that this expected to actually beachieved, taking into account anyimprovement or degradation inefficiency from installation inSingapore and other reasonablefactors


12 Build duration ofthe plant identifiedin item 6 (years)

The time from thecommencement of the major costof development and installationbeing incurred up to the time ofthe plant commissioning. Thisparameter is used to calculatethe financing cost over theduration of the building periodand assumes that thedevelopment costs are incurredevenly across this period. Thebuild duration should be specifiedto reflect this use and meaning asopposed to the actual time fromthe commencement of sitedevelopment to the time of plantcommissioning.


FINAL REPORT

52


13 Economic lifetimeof the plantidentified in item 6(years)

The expected time fromcommissioning todecommissioning of the plant.This number is used to amortisethe capital cost of the plant, andof installation and development.


14 Average expectedutilisation factor ofthe plant identifiedin item 6, i.e.average generationlevel as apercentage ofcapacity (%)

The utilisation factor is theexpected annual proportion ofplant capacity that will be usedfor supplying energy for sale. Itshould exclude station usage,expected maintenance andforced outages and the expectedtime spent providing reservecapacity. The determination ofthe factor should assume that theplant is efficiently base-loaded


15 Fixed annualrunning cost of theplant identified initem 6 ($Sing)

These costs are the fixedoperating and overhead coststhat are incurred in having theplant available for supplyingenergy and reserves but whichare not dependent on the quantityof energy supplied. It isacknowledged that some costsare not easily classified as fixedor variable. The costs expectedto be included in this parameterare:

· Operating labour cost – it isexpected that the plant will berunning for three shifts per dayand seven days per week soall operating labour cost islikely to be a fixed annual cost

· Direct overhaul andmaintenance cost, with anysemi-variable costs treated asannual fixed costs

· Generating Licence· Insurance· Property tax· Costs of emergency fuel· Other charges· Other overhead costs

(a) Determined byEMA, in consultationwith engineering andpower systems expertsin relation to thefollowing values:

· Operating labour· Direct overhaul and

maintenance cost· Costs of emergency

fuel· Other overhead

costs; and

(b) Determined solelyby EMA

· Generating Licence· Insurance· Property tax· Other charges

FINAL REPORT

53


16 Variable non-fuelcost of the plantidentified in item 6($Sing/MWh)

Any costs, other than fuel costs,that vary with the level of energyoutput for a base-load plant andare not covered by item 15

Determined by EMA (inconsultation with theengineering and powersystems experts

17 Proportion of debtby assets

The proportion of debt to totalassets. It is an estimate of theindustry standard ratio for privatesector generators in an economicenvironment similar to Singapore

Determined by EMA (inconsultation with thefinance experts)

18 Risk free Rate (%) The risk-free rate in Singaporeshall be determined as theaverage of the daily closing yieldon a default-free bond issued bythe local government


19 Cost of Debt (%) Risk-free rate plus a premium asdetermined by the Authority.


20 Market RiskPremium (%)

The market risk premiumrepresents the additional returnover investing in risk-freesecurities that an investor willdemand for investing in electricitygenerators in Singapore, asdetermined by the Authority


21 Beta Parameter of scaling the marketrisk premium for calculating thecost of equity as determined bythe Authority. Beta is a measureof the expected volatility of thereturns on a project relative to thereturns on the market, that is, thesystematic risk of the project


22 Tax rate (%) Corporate tax rate applicable togenerating companies inSingapore at the base date.

Determined by EMA

23 Cost of equity (%) The return of equity for thebusiness as calculated from theprevious data. It is calculated asitem 18+ (item 20) (item 21) +item 22

Calculated by EMA (inconsultation with thefinance experts)

FINAL REPORT

54

The economic life of the new entrant is dictated by the rate of development of the heat rate of newerplants and real reductions in capex of newer plants.

Based on the parameters in Gas Turbine World Handbooks of 1994 and 2018, and applying “E” classCCGT’s in 1994 and the latest “F”/”H” class units in the 2018 Handbook34, the average improvement inheat rate per year was assessed as -0.0067 GJ/MWh/y. The real rate of reduction in specific capitalcost was assessed as 1.1% per year.

Applying these rates of change to the new entrant parameters it is calculated that the LRMC of anewer unit would become lower than the SRMC of an incumbent after 38.7 years. Thus, the economiclife of the new entrant plant is the lesser of this value and the technical life of the plant, which would beapproximately 30 years (based on Jacobs industry experience). This calculated economic life issensitive to the gas price which has varied over previous reviews. For consistency with the previousreviews a life of 25 years is recommended in the analysis.

34 Jacobs expects that a new entrant would use “H” technology at this time

B ECONOMIC LIFE

FINAL REPORT

55

Performance analysis of new entrant "F" class CCGT units has been undertaken using the GTPro andGTMaster software suite Version 28. Analyses have been made based on optimisation at the siteaverage ambient and cooling water conditions. Representative performance parameters ascalculated are shown in the following figures:

C THERMODYNAMIC ANALYSIS

FINAL REPORT

56

Figure 12 Performance analysis - Ansaldo "F" class CCGT, clean-as-new, At Reference conditions

FINAL REPORT

57

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

FINAL REPORT

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

FINAL REPORT

59

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

FINAL REPORT

60

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