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AUSTRALIAN ENERGY MARKET OPERATOR

Cost of Construction New Generation Technology

101010-00676 – Report

10 February 2012

Power Level 12, 333 Collins Street MelbourneVIC 3000 Australia Telephone: +61 3 8676 3500 Facsimile: +61 3 8676 3505 www.worleyparsons.com ABN 61 001 279 812 © Copyright 2011 WorleyParsons

WorleyParsons EcoNomics resources & energy


COST OF CONSTRUCTION NEW GENERATION TECHNOLOGY

SYNOPSIS

This report outlines the cost of construction of selected equipment and labour new generation technologies. The cost includes identifying international and local / domestic content. The costs include plant and equipment costs, site preparation and costs typical of inside the fence costs. External costs such as fuel supply, transmission and CO2 pipeline and storage systems are excluded ..

Disclaimer

This report has been prepared on behalf of and for the exclusive use of The Australian Energy Market Operator, and is subject to and issued in accordance with the agreement between The Australian Energy Market Operator and WorleyParsons. WorleyParsons accepts no liability or responsibility whatsoever for it in respect of any use of or reliance upon this report by any third party.

Copying this report without the permission of The Australian Energy Market Operator or WorleyParsons is not permitted.

PROJECT 101010-00676 • COST OF CONSTRUCTIONNEW GENERATION TECHNOLOGY

REV DESCRIPTION

0

2

Draft issued to AEMO

Final Report

Updated Report to delete carbon price from VOM

ORIG

K Hart

REVIEW

P Knispel

WORLEY- DATE PARSONS APPROVAL

J Meister 2Dec11

22 Jan 12

10Feb12

CLIENT APPROVAL

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DATE



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CONTENTS

1 INTRODUCTION ................................................................................................................ 1

2 DESCRIPTION OF CONSULTANCY SERVICES AND DELIVERABLES ......................... 2

2.1 Cost of Construction – New Generation Technologies....................................................... 2

2.2 Establish design basis and plant characteristics ................................................................ 2

2.3 Develop performance parameters ...................................................................................... 2

2.4 Develop Capital Cost Estimates ......................................................................................... 2

2.5 Fuel Cost Estimates ............................................................................................................ 3

2.6 Development of Operating and Maintenance Cost Estimates ............................................ 3

2.7 Generation Technologies .................................................................................................... 4

2.8 Generation Characteristics ................................................................................................. 4

3 AEMO ECONOMIC SCENARIOS ...................................................................................... 6

3.1 Overview ............................................................................................................................. 6

3.2 2012 Scenarios Development Process .............................................................................. 6

3.3 Proposed 2012 Scenario Descriptions ............................................................................... 6

3.4 Planning Scenario - Scenario 3 .......................................................................................... 6

3.5 Fast Rate of Change- Scenario 1 ....................................................................................... 9

3.6 Slow Rate of Change- Scenario 5 .................................................................................... 10

3.7 Scenario Summary ........................................................................................................... 12

3.8 Carbon Price ..................................................................................................................... 13

3.9 Fixed and Variable Operating Cost and Escalation Rate ................................................. 13

4 METHODOLOGY AND ASSUMPTIONS.......................................................................... 15

4.1 Overview ........................................................................................................................... 15

4.2 Cost Estimate Components .............................................................................................. 15

4.2.1 Direct and Indirect Costs ...................................................................................... 15

4.2.2 Contracting Strategy ............................................................................................ 16

4.2.3 Estimate Scope .................................................................................................... 16

4.2.4 Direct Cost Estimate ............................................................................................ 16



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4.2.5 Owners Cost Estimate ......................................................................................... 16

4.3 Forward Curve Assumptions ............................................................................................ 17

4.3.1 Exchange Rate Variation ..................................................................................... 17

4.3.2 Productivity Rate Variation ................................................................................... 17

4.3.3 Commodity Variation ............................................................................................ 18

4.3.4 Technological Improvement ................................................................................. 18

4.4 Regional Annual Build Limits ............................................................................................ 20

4.4.1 Introduction .......................................................................................................... 20

4.4.2 Ability to Source Plant and Equipment ................................................................ 21

4.4.3 Ability to Source Labour ....................................................................................... 21

4.4.4 Ability to Source Specialised Construction Equipment ........................................ 21

4.4.5 Ability to Supply Fuel Feedstock .......................................................................... 21

4.4.6 Ability to Source Water ........................................................................................ 22

4.4.7 Availability of Transmission Infrastructure ........................................................... 22

4.4.8 Permitting Constraints .......................................................................................... 22

4.4.9 Technology Specific Constraints.......................................................................... 22

4.5 National and Regional Maximum Aggregate Build by 2050 ............................................. 23

4.6 NTNDP Regional Factors ................................................................................................. 23

5 TECHNOLOGY BASIS RESULTS AND COST CURVES................................................ 24

5.1 IGCC plant with CCS based on brown coal ...................................................................... 24

5.1.1 Technology description ........................................................................................ 24

5.1.2 Performance ......................................................................................................... 25

5.1.3 Capital Cost Split and Equipment cost trends ..................................................... 25

5.1.4 Expected Technological Improvement ................................................................. 26

5.2 IGCC plant with CCS based on bituminous coal .............................................................. 28

5.2.1 Technology description ........................................................................................ 28

5.2.2 Performance ......................................................................................................... 28





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5.3 Supercritical Pulverised Coal (PC) Technology ................................................................ 31

5.3.1 Technology Description ....................................................................................... 31


5.3.3 Pulverized Coal Supercritical Brown Coal with CCS ........................................... 35

5.3.4 Pulverised Coal Supercritical Bituminous Coal with CCS ................................... 36

5.3.5 Oxy-Combustion Pulverised Coal Supercritical Bituminous Coal with CCS ....... 37

5.4 CCGT Technology based on natural gas ......................................................................... 38

5.4.1 CCGT based on natural gas without CCS ........................................................... 40

5.4.2 CCGT based on natural gas with CCS ................................................................ 41

5.5 Solar Thermal Technologies ............................................................................................. 43

5.5.1 Description of Technology - Solar Thermal ......................................................... 43

5.5.2 Compact Linear Fresnel Technology ................................................................... 43

5.5.3 Parabolic Trough Technology .............................................................................. 46

5.5.4 Central Receiver Technology ............................................................................... 49

5.5.5 Solar Thermal Future Improvements ................................................................... 51

5.6 Photovoltaic PV Fixed Flat Plate ...................................................................................... 52

5.6.1 The Berkeley Report ............................................................................................ 53

5.6.2 US DOE $1/Watt program ................................................................................... 53

5.6.3 Capital Cost basis ................................................................................................ 54

5.7 Wind Technology .............................................................................................................. 57


5.7.2 Wind Resource..................................................................................................... 57


5.7.4 Capital Costs ........................................................................................................ 58

5.7.5 Internationally Sourced Equipment Costs ............................................................ 59

5.7.6 First Year Available for Construction ................................................................... 59

5.7.7 Typical New Entrant Size ..................................................................................... 59

5.7.8 Operations and Maintenance ............................................................................... 60

5.8 Geothermal ....................................................................................................................... 63



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5.8.2 Australian Experience .......................................................................................... 64


5.8.4 Resource Replenishment ..................................................................................... 70

5.9 Integrated Solar Combined Cycle (ISCC) ......................................................................... 70

5.10 Cost Curves .................................................................................................................. 71

APPENDIX 1: TECHNOLOGY AND COST CURVES

APPENDIX 2 BATTERY LIMITS

APPENDIX 3 - TYPES OF GENERATION PLANT IN AEMO REGIONS

APPENDIX 4 - PLANT SCHEMATICS

4.1 –IGCC PLANT WITH CCS BASED ON BROWN COAL

4.2–IGCC PLANT WITH CCS BASED ON BITUMINOUS COAL

4.3–PULVERIZED COAL SUPERCRITICAL BROWN COAL WITH CCS

4.4–PULVERISED COAL SUPERCRITICAL BITUMINOUS COAL WITH CCS

4.5–CCGT BASED ON NATURAL GAS

4.6–CCGT WITH CCS BASED ON NATURAL GAS

APPENDIX 5 REGIONAL CAPITAL COST MODIFIERS

APPENDIX 6 – REFERENCES

AUSTRALIAN ENERGY MARKET OPERATOR COST OF CONSTRUCTION NEW GENERATION TECHNOLOGY

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1

1 INTRODUCTION

The purpose of this report is to provide a contemporary estimate of current and future costs of a wide range of electricity generation technologies, which is realistic and balanced, with transparent assumptions and methodologies and is developed and agreed in conjunction with stakeholders.

This report builds on, and updates, the information presented in a report prepared and issued by WorleyParsons Services Pty Ltd (WorleyParsons) to the Australian Energy Market Operator (AEMO) in December 2010. The review considers inside the facility boundary costs and assumes that external infrastructure is available to service the facility such as:

• Availability of fuel at the boundary • Availability of CO2 storage – considered to be viable from 2023 in this report • Availability of transmission infrastructure to remote areas to support renewable

development such as geothermal and to a lesser extend wind and solar The above infrastructure will typically impact project viability as they are a of significant capital cost.



2

2 DESCRIPTION OF CONSULTANCY SERVICES AND DELIVERABLES

2.1 Cost of Construction – New Generation Technologies

WorleyParsons has identified the cost of construction of a typical new generation technology for each location suitable for the development of particular technologies. The elements that make up this cost are broadly identified by international content and local/domestic content. Factors affecting the local and international content are specifically identified such that assumptions that affect the overall cost can be uniquely varied.

The costs to be considered as part of each generation project includes plant and equipment costs, typical electrical and site preparation costs and fuel and cooling costs inside the nominal project fence that delineates the separation between the project and the grid. External factors such as electrical connection, fuel pipelines or delivery handling systems are excluded.

The estimates are calculated on the basis of a new project starting in each calendar year from 2012 to 2032.

The estimates for technologies not yet at a commercial stage of development include the cost of bringing the technology up to commercialisation. The benefit of learning by doing is represented as a longer term projection of price reduction for the technologies.

2.2 Establish design basis and plant characteristics

This task establishes the following:

• Technical parameters of the power generation technologies; • Establish fuel properties; and • Establish emissions intensity for the plant design.

2.3 Develop performance parameters

Performance parameters established include:

• Gross power output; • Net power output; • Thermal efficiency; • Auxiliary power consumption; and • Capacity Factor.

2.4 Develop Capital Cost Estimates

Capital cost estimates for coal and gas fired technologies are established using specialist software that includes the latest available Australian cost factors. For solar, wind and geothermal technologies WorleyParsons’ in-house data, public domain data, and public domain reports have been investigated to provide a contemporary cost base for these technologies.



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The objective is to ensure that the capital cost estimates are derived consistently for the electricity generation technologies.

This is achieved for fossil technologies by utilizing a consistent software and cost data base. For other technologies where there is no consistent pricing basis, only a subjective analysis is possible. This was based on the available information and considered / adjusted based on WorleyParsons’ experience with these technologies.

A breakdown of capital costs is provided for each technology based on imported and local equipment and installation costs.

2.5 Fuel Cost Estimates

WorleyParsons has employed ACIL Tasman to provide fuel cost estimates.

The cost estimates include the cost of bringing new fields to market and the costs of new production facilities and pipelines.

Fuel cost estimates are developed based on the projected lifetime operation of the power plant for the period 2012 to 2032. The analysis includes all factors that affect the price of fuel, with the exclusion of a carbon tax (which will be applied separately).

Where possible, the fuel price includes a price volume relationship for each fuel source for each NTNDP zone within the NEM. Note that the following restriction on fuel zones apply due to fuel availability:

• Brown Coal – Latrobe Valley

• Black Coal – Central Queensland, Southwest Queensland, Southeast Queensland, Northern New South Wales, Central New South Wales (limited by perceived CCS Storage capability)

• Natural Gas – all zones.

Where appropriate the same factors have been used in the technology scenario projections as those used in the fuel cost projections.

All costs are developed on a high level devoid of site specific information which often has a significant effect on variability of project costs.

The ACIL Tasman report is provided as a separate report to AEMO.

2.6 Development of Operating and Maintenance Cost Estimates

A considered view on cost estimates for fixed and variable operating and maintenance costs is provided. These are high-level estimates based on WorleyParsons’ in house data, public domain information and industry-based software for gas-fired technology. The Owners’ operating and maintenance practices for any given specific facility significantly affects the variability of these costs.



4

2.7 Generation Technologies

The following generation technologies are evaluated:

1. IGCC plant with CCS, based on brown coal;

2. IGCC plant with CCS, based on bituminous coal;

3. Pulverized coal supercritical plant with CCS, based on brown coal;

4. Pulverized coal supercritical with CCS, based on bituminous coal;

5. Oxy-combustion pulverized coal supercritical with CCS, based on bituminous coal;

6. CCGT plant, based on natural gas;

7. CCGT with CCS, based on natural gas;

8. Solar thermal, compact linear Fresnel reflector technology without storage;

9. Solar thermal, parabolic trough technology with 6 hours storage;

10. Solar thermal, central receiver technology with 6 hours storage;

11. Solar PV, non-tracking;

12. On shore wind turbine, 100 MW wind farm;

13. Geothermal, HAS;

14. Geothermal, EGS; and

15. Integrated solar combined cycle (ISCS); parabolic trough with combined cycle gas (solar component).

2.8 Generation Characteristics

For each technology the following characteristics are identified (as applicable):

• Technology description; • Fuel type; • Capital costs; • Local equipment / construction costs – based on installation and 50% equipment cost; • International equipment costs; • Construction % of capital; • First year available for construction; • Typical new entrant size; • Regional annual build limit; • National and regional maximum aggregate build by 2050; • Economic life; • Lead time for development (years); • Minimum stable generation level (% capacity); • Thermal efficiency (sent out – HHV);



5

• Thermal efficiency (sent-out HHV) learning rate (% improvement per annum); • Auxiliary load (%); • FOM ($/MWAC/year) for 2012; • FOM escalation rate (% of CPI); • VOM ($/MWh sent-out) 2012; • VOM escalation rate (%of CPI); • Percentage of emissions captured (%); • Emissions rate per GGCO2e/MWh or GGCO2e/GJ fuel; and • Cost confidence level (based on source data accuracy to provide a % band or ranking for

each technology).

For each of the above mentioned technologies, cost curves are established according to the following five scenarios:

Scenario 1 – Fast Rate of Change.

Scenario 2 – Fast World Recovery.

Scenario 3 – Planning.

Scenario 4 – Decentralised World.

Scenario 5 – Slow Rate of Change.



6

3 AEMO ECONOMIC SCENARIOS

3.1 Overview

In order for AEMO to be able to further use the plant performance data, capital cost data and operation and maintenance cost data collated for the various power generation technologies examined under the scope of this study, the data was required to be provided for a range of economic scenarios. Broadly speaking, the scenarios encompass the possible variation of high level economic parameters such as trends in future GDP, carbon price (if applicable), fuel costs (considered in a separate study outside of WorleyParsons’ scope of work) and technology development issues. According to AEMO specification, values for technology and economic parameters were assigned to five different scenarios, ranging (in summary) from rapid economic growth, technology development and greenhouse abatement goals, through to a low-growth, low-technology development, unpriced carbon emissions scenario.

The use of sensitivities based on a range of potential outcomes (rather than just carbon price) was required by AEMO so that the results of the study could be usefully applied to future modelling as the actual future economic and technological conditions change.

3.2 2012 Scenarios Development Process

In September 2011, as part of its preparation for the 2012 planning documents, AEMO invited industry representative bodies to nominate people to be part of a Stakeholder Reference Group (SWG) to assist in the development of revised scenarios drawing on the previous scenario designs.

The outcomes of this process were used to specify the scenarios for which AEMO required WorleyParsons to model the cost and performance data, as well as the timelines for the power generation technologies included in the scope of the study.

WorleyParsons has used the qualitative descriptions of the driver trend changes, and selected proxy variables and dependent cost development functions. These were then applied to the results of the technology capital cost and performance estimates in order to provide forecast data over the specified period from 2012 to 2032.

3.3 Proposed 2012 Scenario Descriptions

For the 2012 scenarios AEMO developed a central “planning scenario” that represented their best estimate of how the future will develop, given the currently known, well-advanced and anticipated changes.

The other scenarios were designed to provide outlying views of the future around this central scenario.

3.4 Planning Scenario - Scenario 3

The planning scenario was a best estimate by AEMO and the stakeholder group members of the future of the energy industry, including identified and quantified key drivers of change. The scenario



7

was an attempt to quantify the most likely trajectory of the industry, as opposed to business as usual (which AEMO and the stakeholders determined to be less likely than the changes defined in the planning scenario).

The identified drivers have been listed in the table below, as provided by AEMO.

Factor AEMO Scenario Prediction

WP (this study) Proxy Variable

Impacted Capital Cost Components

National Economic Growth

Medium estimate consistent with current growth

Australian GDP, assume 2.5% year on year growth

Commodity/construction & Equipment

Exchange Rate Exchange rate (per ACIL Tasman supplied data)

Australian dollar moving to peak of 1.13 USD/AUD by 2016-2017,

falling to 0.86 USD/AUD by 2031-2032

Global economic growth

Global recovery continues with ongoing growth in the demand for Australian commodities, particularly resources

Major equipment supplier countries average GDP growth 2.5%

Equipment (50% sensitivity)

Population growth Moderate growth GDP and specific (output/hour worked) labour productivity

Commodity/Construction (as per econ growth) and Labour prod. (+0.8% p.a.)

Carbon Price The Treasury Core modelling forecast - 5% reduction by 2020 trajectory- starting @ $23/tonne 1 July 2012 (as per the carbon price as legislated).

$23/tonne CO2 Commodity (5% weighted average price sensitivity), and major equipment (1% sensitivity)

Renewable Energy Target

LRET – Remains in place to 2030 with no significant

Technology-specific development, cost reduction curves

Technology-specific cost reduction curves



8




changes from the bi-annual reviews

SRES – Remains in place to 2030 with currently announced reductions to the STC multiplier

(due to selection of technology and build out)

East Coast LNG export

Commencing 2014 and reaching approximately 1200 PJ p.a. by 2016

Affects fuel input via gas prices, some sensitivity for commodity prices.

See domestic gas prices

Domestic gas prices


2% commodity sensitivity

Global technology R&D

Moderate Technology-specific development, cost reduction curves (due to selection of technology and build out)


Demand side response

Moderate Affects regional build out but not capital cost

Electric vehicle penetration

Moderate Effect on regional build but not capital cost



9

3.5 Fast Rate of Change- Scenario 1

Under this scenario, the AEMO stakeholder group specified high-growth, dynamic economic conditions but also cuts to national greenhouse emissions of 25%.

The scenario drivers for scenario 1 are given in the table below:





High growth Australian GDP, assume 3% year on year growth

Commodity

Exchange Rate Exchange rate (per ACIL Tasman supplied data)

Australian dollar moving to peak of 1.20USD/AUD by 2016-2017, falling to 0.91 USD/AUD by 2031-2032


High Major equipment supplier countries average GDP growth 3%

Equipment (50% sensitivity), Commodity.

Population growth Moderate growth GDP Commodity/Construction

Carbon price The Treasury Core modelling forecast - 5% reduction by 2020 trajectory

Carbon price impact on commodity and equipment, as per noted sensitivities

Commodity (15% weighted average price sensitivity), and major equipment (2% sensitivity)

East Coast LNG export High global growth, high China/India/Japan LNG demand.


See domestic gas prices

Domestic gas prices Affects fuel input via gas prices, some sensitivity for commodity prices.

3% commodity sensitivity.



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Global technology R&D High Technology-specific development, cost reduction curves (due to selection of technology and build out)


Demand side response High Affects regional build out but not capital cost

Electric vehicle penetration

High Effect on regional build but not capital cost

3.6 Slow Rate of Change- Scenario 5

Scenario 5 is one of low economic growth, both domestically and internationally, increased credit costs, low commodity prices and no Australian carbon price (due to legislation repeal).

R&D in new low emission generation technologies is slow, resulting in lower and slower amounts of technological improvement for all technologies. The scenario drivers for scenario 5 are given in the table below:



11





Low growth Australian GDP, assume 1% year on year growth

Commodity

Exchange Rate

Exchange rate (per ACIL Tasman supplied data)

Australian dollar moving to peak of 0.99USD/AUD by 2016-2017, falling to 0.75 USD/AUD by 2031-2032


Low Major equipment supplier countries average GDP growth 0.5%

Equipment (50% sensitivity), Commodities flat.

Population growth

low growth GDP Commodity/Construction

Carbon price No Australian carbon price

(assume no carbon protectionism by trading partners either)

No impact No impact

Global technology R&D

High Technology-specific development, cost reduction curves (due to selection of technology and build out)




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3.7 Scenario Summary

Scenario 1 Scenario 2 Scenario 3 Scenario 4 Scenario 5

Econ

omic

s

Scenario Title

Fast Rate of Change

Fast World Recovery

Planning Decentralised World

Slow Rate of Change

Economic Growth

High High Medium Medium Low

Commodity Prices

High High Moderate Medium Low

Productivity Growth

High High Moderate Moderate Low

Population Growth

High High Moderate Low Low

Gre

enho

use

Carbon Reduction Target

High 25% reduction Treasury high scenario

Medium

5% reduction Treasury core scenario

Medium


Medium


Zero

No Carbon Price

Renewable Energy Target

Remains Remains Remains Remains Remains

Fuel

s

International Coal Prices

Increasing Stable Stable Stable Falling

East Coast Gas Prices

LNG East Coast Production


Tech

nolo

gy

R&D Strong Moderate Moderate Weak Moderate

Distributed Generation Penetration

High Moderate Moderate High Low

Penetration of Electrical Vehicles

High Moderate Moderate High Low



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3.8 Carbon Price

The prices in this table are based on the Treasury analysis for the Clean Energy Future Package.

Carbon Cost Assumptions

Zero

No Carbon Price

Medium

5% reduction on 2000 emissions by 2020

High

25% reduction on 2000 emissions by 2020

Clean energy futures legislation repealed

Treasury core scenario Treasury High Scenario

Scenario 5 Scenarios 2, 3 and 4 Scenario 1

No price on carbon over the forecast period

Moderate emission reduction targets both in Australia and internationally.

In Nominal Dollars

Three year fixed price period

2012/13: 23.00$A/tCO2-e

2013/14: 24.15$A/tCO2-e

2014/15: 25.40$A/tCO2-e

Moving to the flexible price in 2015/16

$29/t CO2-e

Rising at 5% plus inflation

A strong emissions reduction

In Nominal Dollars

Three year fixed period

ppendix 1 2012/13: 23.00$A/tCO2-e

2013/14: 24.15$A/tCO2-e

2014/15: 25.40$A/tCO2-e

Moving to the flexible price in 2015/16

A$61/t CO2-e

Rising at 5% plus inflation

Note that a carbon tax, where relevant to the technology, is a variable operating cost levied on the basis of carbon emitted, which simplifies through efficiency and emissions intensity to a carbon tax per MWh of generation. It should be noted, however, that the impact of the carbon tax on variable operating and maintenance costs has been omitted from this report at AEMO’s request.

3.9 Fixed and Variable Operating Cost and Escalation Rate

In the tables for each technology the following elements are included in the Fixed O & M cost estimates as an annual cost per MW capacity:-

• Direct and home office labour and associated support costs



14

• Fixed service provider costs

• Minor spares and fixed operating consumables

• Fixed inspection, diagnostic and repair maintenance services

The rate is considered common for all technologies.

The following elements are included in the Variable O & M costs as a cost rate per MWh of sent out energy:-

• Chemicals and operating consumables that are generation dependent – e.g. raw water, water treatment chemicals;

• Auxiliary power;

• Scheduled maintenance for entire plant including balance of plant; and

• Unplanned maintenance.

Fuel costs and carbon costs are excluded from VOM costs.

Scenario FOM Escalation Rate (%of CPI) VOM Escalation Rate (% of CPI)

1 150 150

2

3 150 150

4

5 100 100

The escalation rates estimated in the table above reflect the trend that sees power station labour costs (both in-house and service provider) generally increasing at rates well above CPI as Enterprise Bargaining Agreements are negotiated in competition with other industries seeking the same skills; usually in the same geographical area. Spare parts typically escalate at a mix of the metals index and labour rate increases.

These escalation pressures dominate the FOM escalation rate. The VOM escalation rate is also estimated to exceed CPI under the planning and growth scenarios as CPI is typically a poor indicator of increases in utility and maintenance costs. In each case, a number of the household variables that exert downward pressure on the CPI measure are not present within power station O & M costs.



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4 METHODOLOGY AND ASSUMPTIONS

4.1 Overview

The cost estimating methodology used to assess current costs for the respective generating technologies included benchmarking against recent project costs known to WorleyParsons and comparison with forward estimates from various industry sources.

For thermal technologies such as IGCC, Supercritical Pulverised Coal (PC), CCGT/OCGT and Biomass, the respective cost estimates were based on relevant databases contained in standard software such as Thermoflow’s GTPro, GTMaster, SteamPro and Peace. This software models plant performance and provides EPC and total project cost data.

All cost estimates derived using such software were based on current Australian conditions such as exchange rate, materials and labour cost.

EPRI’s SOAPP-CT O & M Cost Estimator software was used to develop a number of fixed and variable operations and maintenance cost estimates for gas turbine based plant configurations.

In general, data for future trends was based on Original Equipment Manufacturer (OEM) information, industry body and industry analysis papers and WorleyParsons’ internal data.

For renewable technologies such as solar, geothermal, wind and wave, our cost estimate databases are based on our direct experience in projects, surveys of vendors’ products, access to industry association papers and public domain material.

4.2 Cost Estimate Components

4.2.1 Direct and Indirect Costs

The total capital cost estimate figures (in A$/kW) for each technology assume direct and indirect cost components. WorleyParsons cost curves are expressed as A$/kW for net power sent out.

The following items are excluded from the direct and indirect capital costs:

• Escalation throughout the period-of-performance;

• All taxes;

• Site specific considerations including but not limited to such items as seismic zone, accessibility, local regulatory requirements, excessive rock, piles, lay down space, etc;

• For CCS cases, the cost associated for CO2 injection wells, pipelines to deliver the CO2 from the power plant to the storage facility and all administration supervision and control costs for the facility;

• Import tariffs that may be charged for importing equipment to Australia or shipping charges for this equipment; and

• Interest during construction and financing costs.



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4.2.2 Contracting Strategy

The estimates are based on an Engineering/Procurement/Construction (EPC) approach utilising a main contractor and multiple subcontracts working under the main contractor. This approach provides the owner with greater certainty of costs associated with the facility, but attracts risk premiums that are typically included in an EPC contract price.

4.2.3 Estimate Scope

The estimates represent a complete power plant facility on a generic site.

Site-specific considerations such as soil conditions, seismic zone requirements, or unique local conditions such as accessibility, local regulatory requirements, etc. are not considered in the estimates.

The battery limits for each technology are detailed in Appendix 2 .

Labour costs are based on 2012 Australian rates and productivities, in a competitive bidding environment.

4.2.4 Direct Cost Estimate

Direct cost estimate for each technology assumes costs associated for all major plant, materials, minor equipment and labour to develop the respective power plant to the stage of commercial operation.

4.2.5 Owners Cost Estimate

Provision has been made for development costs necessary to cover expenses prior to start of construction and all non EPC hard costs during construction. Specific development cost items that are assumed are listed below:

• Studies and Project Development;

• Site Acquisition;

• Legal Fees;

• Project Support Team;

• Development Approvals;

• Duties and Taxes;

• Operator Training;

• Commissioning Fuel; and

• Commissioning and Testing.



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4.3 Forward Curve Assumptions

Our methodology used to produce forward cost curves assumes that the 2012 capital estimate is broken down into three cost components namely; commodity, equipment and labour cost components.

There are two levels of factors that were applied to estimate the forward cost curve. The first level assumes the impact for:

• Exchange rate variations over the period 2012 to 2032 for each of the five scenarios; • Productivity variations for each of the scenarios over the applicable timeframe; and, • Commodity index/variation over the applicable timeframe for each scenario.

The second level assumes the technological improvement factor that is applied on a year by year basis over the period 2012 to 2032.

4.3.1 Exchange Rate Variation

In the interest of cost estimate forecast compatibility, with the results of the fuel cost study being undertaken by ACIL Tasman, the same foreign exchange forecast curves were applied for this study as used in the ACIL Tasman fuel study.

Figure 1 : Exchange Rate Variation as Applied

4.3.2 Productivity Rate Variation

Specific labour productivity growth (expressed as worker output per hour worked) was used to modify the labour component of the capital cost estimates for each technology. A full treatment of total labour productivity (including both hours worked (population dependent) and specific output) was not undertaken, but rather a baseline assumption of 0.8% per annum improvement in output per hour was assumed for the planning scenario. For the fast rate of change, high growth scenario, 2% improvement was used, while for the low growth, 0.2% was applied. Static or negative change in output per hour was not considered for any scenario.

0.00

0.20

0.40

0.60

0.80

1.00

1.20

1.40

2012

-13

2013

-14

2014

-15

2015

-16

2016

-17

2017

-18

2018

-19

2019

-20

2020

-21

2021

-22

2022

-23

2023

-24

2024

-25

2025

-26

2026

-27

2027

-28

2028

-29

2029

-30

2030

-31

2031

-32

$US/

$AU

D

Fast rate of change Fast w orld recovery Planning (Treasury)Decentralised w orld Slow rate of change



18

Scenario Scenario 1 Scenario 3 Scenario 5

Rate of specific labour productivity improvement

2.0% 0.8% 0.2%

4.3.3 Commodity Variation

Based on the description of the AEMO scenarios, commodity variation for the scenarios was assumed to vary approximately as with the GDP growth rate as follows:

Scenario 1 Scenario 2 Scenario 3 Scenario 4 Scenario 5


Similarly as for the exchange rate, Scenario 1 was assumed to have the highest commodity variation with reducing values to the lowest value for Scenario 5.

The value and profile for commodity variation was linked to the average GDP/GSP profile for Australia over the period 2012 to 2032.

The KPMG report entitled “Economic Scenarios and Forecasts for AEMO – 2009 Update” the average GDP growth rate over the forecast horizon from 2012 to 2032 is 3.3% for the high Scenario assumed Scenario 1 (fast rate of change), 1.7% for the low scenario, assumed Scenario 5 (slow rate of change) and 2.5% for the medium scenario.

4.3.4 Technological Improvement

The impact for technological improvement has probably the most influence over pricing trends for the different generating technologies during the period 2012 to 2032.

In general we assumed the trend expected for each technology according to the level of maturity for that technology and in accordance with typical Grubb curves1 such as the generic curve shown below:

1 Australian Electricity Generation Technology Costs – Reference Case 2010, February 2010, EPRI



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Figure 2: Impact for Technological Improvement

For fossil fuel technologies with CCS technology, significant improvement in process and efficiency gains would be realised throughout the assessment timeframe as new CCS processes are proven and commercialised. Variation between scenarios assumed varying rates for commercialisation for improved technology to reflect early commercialisation for a fast rate of change (scenario 1) to a delayed commercialisation for a slow rate of change (scenario 5).

Improvements in CCS technologies were generally assumed to be step changes occurring as the new technology is assumed to be introduced.

For CCGT and Supercritical PC technologies there are still gains to be made as new materials are implemented and improvements to overall performance are implemented. In cases where small changes occurred often, a linear rate of improvement was assumed over the assessment period.

Likewise IGCC technology is expected to improve in output and performance at a faster rate over the next decade and slowing down as the technology matures and gains become smaller.

Renewable technologies have varying levels of development maturity as seen by the following Grubb curve2. While wind and solar are approaching maturity, technologies such as biomass and wave energy (not assessed in this report) are still in the development phase.

The last two years have seen rapid growth in solar PV manufacturing capacity, which may move the unit cost of PV cells and modules rapidly to the right on the Grubb curve. Despite the flattening of the curve, major reductions are still possible in the areas of building materials (solar roofing shingles,

2Dynamic Characteristics of Wave and Tidal Energy Converters, OES-IA Document No. T0321



20

solar building facia, semi-transparent thin-film solar PV window panes etc) and non-module components (inverter systems) which form major portions of solar PV capital costs.

Figure 3: Anticipated Cost of Renewable Technology Development

4.4 Regional Annual Build Limits

4.4.1 Introduction

For the purposes of this report, it is assumed the regional annual build limit refers to the physical ability to deliver a project rather than an ability to establish a commercial case to progress a project. Thus annual build limits are defined primarily by supply / demand constraints.

WorleyParsons have considered the opportunities and constraints influencing the regional annual build limit for the technologies assessed in this report, and have concluded that there are a number of principal influencing factors that will impact on the annual build capacity across all technologies, in addition to some technology specific factors.

The principal factors impacting the regional annual build limit will include:

1. the ability to source plant and equipment;

2. the ability to source sufficient general and specialized labour to construct the plant;

3. the ability to source necessary specialised equipment for construction of the plant;

4. the ability to source sufficient fuel feedstock to supply to planned build;

5. the ability to source water;

6. the availability of sufficient transmission infrastructure to export planned generation capacity;



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7. permitting constraints.

In addition to these limitations that generally apply across all technologies, there are some specific issues that apply to specific technologies, such as availability of carbon storage reservoirs for CCS, and acceptable penetration of variable (non-scheduled) generation into the network.

These issues will be addressed in more detail below.

4.4.2 Ability to Source Plant and Equipment

The majority of specialised components for all of the generation categories are manufactured internationally for Australian projects. This is expected to continue to be the case for the forecast period. The demand for equipment in Australia is unlikely to comprise a significant proportion of the manufacturing capacity, thus variation in Australian demand in isolation is unlikely to have a significant impact on the supply of plant and equipment.

Significant variation in international demand for specific technology may have an impact on the supply to Australia, however, such future constraints are difficult to forecast.

Therefore, it is the view of WorleyParsons that constraints on the ability to source specialised plant and equipment are unlikely to contribute significantly to regional annual build limits.

4.4.3 Ability to Source Labour

With the high level of economic activity in the resources sector, skilled labour constraints have become evident in the Australian economy. This is particularly the case in the mineral rich and more remote parts of the country. Such skilled labour shortages are often cyclic and dependent on the general growth patterns in the broader global economy.

WorleyParsons has considered the impact of a strong global economy on the capital cost for delivery of projects, and the impact of such growth is considered to be experienced as a higher cost to deliver rather than a constraint on the annual build limit.

4.4.4 Ability to Source Specialised Construction Equipment

The delivery of some large scale generation projects may require the use of specialised equipment; particularly craneage.

WorleyParsons does not believe that an equipment constraint will impact on the regional annual build, but rather, as with the discussion on labour, under a high economic activity scenario, may have an impact on the cost to deliver the projects.

4.4.5 Ability to Supply Fuel Feedstock

This analysis is premised on the assumption that planned development of new generation capacity is on the basis of the availability of sufficient available fuel supply. Constraints in infrastructure to supply the fuel to the generation plant may impact on the ability to deliver a project, however, solutions to fuel supply constraints are assumed to be incorporated into the development of a new generation project.



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4.4.6 Ability to Source Water

Regional availability of water, both now and into the future, is likely to impact on the annual build limits for particular technology types. Where water is currently in short supply, or may become scarcer, it is likely that the application of wet cooled thermal generation technologies may be limited and air cooling would become the chosen technology.

4.4.7 Availabil ity of Transmission Infrastructure

One of the primary constraints on development of projects in a region is the availability of sufficient transmission capacity to effectively deliver the generation to the load. As with the impact of fuel supply, solutions to transmission constraints are assumed to be incorporated into the development of a new generation project, and thus not considered a separate factor limiting the regional annual build limit.

4.4.8 Permitting Constraints

Constraints on permitting for new build generation capacity can result from a number of factors including social acceptance of development, policy and legislative requirements and a capacity to process approvals. Such constraints can have a significant impact on the timeframe to deliver a project, and thus the annual build will be limited by the ability to clear necessary permitting steps in development.

Necessary permitting will also be influenced by government policy, both at a State and Federal level.

While the ability to deliver projects and associated approval timeframes can be estimated under present policy settings, future changes to policy can have an impact on the delivery time and the annual build limits.

4.4.9 Technology Specific Constraints

In addition to the principal factors impacting the annual build limit as outlined above, there are a number of factors specific to technologies that will impact the ability to deliver projects in a specific region.

These will include:

CCS: the availability to access appropriate storage structures at an economic cost.

Wind: Ability to access land with an appropriate wind resource in a specific region. This can be influenced by both the topography and the division of land and population density.

Wind/Solar: penetration of non-scheduled and semi-scheduled generation into the network. There are a number of studies suggesting that at penetration levels above 25 to 30%, the cost to integrate additional non-scheduled variable generation into the network, can increase. The extent to which this will be a regional constraint will depend on the future connection infrastructure and systems operational regimes.



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4.5 National and Regional Maximum Aggregate Build by 2050

It is assumed, for the purposes of this report, that the national and regional maximum aggregate build by 2050 will be determined by the commercial case to deliver different technology projects, within the constraints outlined in Section 4.4.

The typical life of generation plant is in the order of 30 to 60 years, depending on technology. Therefore, it is anticipated that by 2050, the majority, if not all, of the current generation fleet in Australia will be replaced with new build generation.

The distribution and capacity of the different technology types will be dependent on the economic case for development (dependent on capital costs, off-take values and operational costs), and the application of the constraints to the delivery of projects within regions.

4.6 NTNDP Regional Factors

Graphs of regional capital cost multipliers are provided in Appendix 6 based on current year (2011) estimates. The multiplier values are based on technology type. The capital cost data presented in section 5 is based on a 1.0 multiplier.



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5 TECHNOLOGY BASIS RESULTS AND COST CURVES

This section provides the technology basis and descriptive material for developing each technology type characteristics. Information provided includes descriptive material and commentary for each technology, as well as tabulated information specifically addressing the technology characteristics.

Cost curves were plotted for each of the 15 technologies and the tabulated values for these curves are provided in Appendix 1. The cost curves are based on all costs for each scenario starting at the same level in year 2012 and then, based on the scenario and the assumptions for that scenario, diverging to provide a cost band up to 2032.

5.1 IGCC plant with CCS based on brown coal

5.1.1 Technology description

An integrated brown coal gasification and combined cycle (IGCC) with carbon capture and storage (CCS) technology is a combination of an IGCC technology based on brown coal and a CCS technology. Brown coal, which is the primary source of fuel in this type of plant, is converted into synthetic gas (syngas) through a gasifier to power the combustion turbine, which subsequently produces heat to raise steam in a heat recovery steam generator (HRSG) to power a steam turbine. CO2 is captured to reduce discharge into the atmosphere.

Integrated brown coal gasification and combined cycle (IGCC) power generation technology is moderately developed with a limited number of gasifier and gas turbine manufacturers currently offering commercial plants. Australian experience of the technology is limited to a 10 MW pilot plant which has been built and operated by HRL using an air-blown gasifier.

In Australia, this type of technology may be developed in Victoria due to large brown coal reserves in this region. Although the Arkaringa brown coal resource in northern South Australia may be developed for gasification and coal-to-liquids conversion with an associated IGCC power generation component, power would not be the primary energy export (and may not be possible, depending on the feasibility of a transmission grid connection to the remote deposit) from such a development and hence is not considered under this study. The high moisture content of Victorian brown coal results in costly long distance transportation and thus the brown coal options were only considered for the Latrobe Valley region.

Based on the proposed capacity for IGCC plants in Victoria and South Australia such as Arkaringa IGCC and HRL integrated drying and gasification combined cycle (IDGCC) respectively, the typical new entrant size for a brown coal fuelled IGCC plant with CCS is 500 MW (net).

Thermoflow software version 21 was used to model and derive the performance parameters for this technology including the capital cost. The cost factors used for Australian based models based on default values provided by the Thermoflow software were 1.3 for equipment and commodity and 2.025 for labour. Brown coal fuelled IGCC with carbon capture was modelled around two oxygen-blown, dry-feed, Shell gasifiers with convective cooling of the raw syngas, fuelling GE 9F gas turbines. The GE9FA was selected due to its higher thermal efficiency, since if carbon capture and



25

storage is to be carried out, a higher efficiency gas turbine will require less fuel use for a given power output, which may provide savings in the carbon capture, transmission and storage portions of the capital and operating costs. . Capture and compression of CO2 from the syngas stream was modelled in the process as an amine absorbent process, after the acid gas cleanup and water-gas shift stages of syngas processing. Other alternative carbon capture processes could include integrated acid gas and carbon dioxide removal (such as Selexol process) which may vary the plant efficiency and output slightly.

5.1.2 Performance

The results of the plant performance modelling for this baseline configuration were a net plant output of 552 MW, and a net efficiency of 25.5% (Latrobe Valley brown coal basis). The net plant output and the net efficiency are lower than last year due to recent information on this technology reveals higher auxiliary load required than previously expected. As a result of higher auxiliary load, the capital cost per unit of electricity generated ($/kWh) is higher than predicted in 2010 and the overall plant efficiency is lower.

A minimum of 50% generation capacity is required to maintain a stable gasification process and effective gas cleaning.

The total emission rate is 151kgCO2e / MWh sent out.

The auxiliary load is approximately 384 MW (including transformer losses), which is equal to 41% of the total generated power.

No full scale IGCC plants with full CO2 capture such as this exist to date, and therefore accurate cost benchmark data is not available.

A cost adder of 24% was included to allow for additional coal drying equipment in case of typical Victorian brown coal resources, which have typical moisture contents in the 50-70% range.

5.1.3 Capital Cost Split and Equipment cost trends

The capital cost split for Brown Coal IGCC with CCS is 21% commodity, 50% equipment and 29% labour. The high portion of capital cost apportioned to equipment cost leads to a large currency exchange rate exposure of future plant capital costs, as well as to non-exchange rate trends such as downward cost movement of technologies along a learning (or "Grubb") curve.

Therefore, if the Australian dollar remains strong such as would be characteristic for scenario 1, the downward cost trends of technology improvements would dominate, while if the Australian dollar weakens from its current position, as typical for the weak growth, the scenario 5 case, overall capital costs for IGCC brown coal with CCS are expected to increase.



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5.1.4 Expected Technological Improvement 3

With respect to the curves estimating technological improvement over time, a similar technology improvement was assumed as for the other IGCC cases, with an additional, sharp decline in capital cost of 12-17% over the otherwise steady cost improvement was applied. Generally the decline in capital costs are based on the predictions described by the EPRI roadmap where for IGCC there is expected to be improvements in the following:

• Improved reliability and flexibility of gasifier • O2 separation • H2 turbines and fuel cells • Carbon capture • Successful demonstration of a full scale IGCC-CCS plant.

Therefore the sharp decline accounts for a major improvement in the costs of carbon capture equipment and O2 separation due for commercial deployment of the technology following successful large scale demonstrations, which is forecast to commence from around 2017/18 for the high growth scenario 1, or later, around 2020/21, for the low growth scenario 5. Intermediate scenarios were set with a similar change to commence in the years between these two cases.

Curves for the rate of technological cost improvement were constructed, corresponding to each of the scenarios. Scenario 5, corresponding to low growth, assumed a net real technology $/kW improvement of equipment costs of 5% by 2032, or 0.25% per year. By contrast, the same measure for scenario 1 assumed a steady cost improvement of 1% per year, with additional, more rapid technological improvements between 2017 and 2020, leading to a net equipment cost improvement in real terms of 25% by 2030.

The additional cost improvements from 2017 to 2020 were included to take into account expected transition of more specialised equipment supply to low cost countries, and as a secondary influence, possible unit capacity cost improvements due to gas turbine and gasifier technology developments. Such improvements could include technologies such as widespread introduction of steam cooling technology to gas turbine hot gas path components.

3 Rubin, E.S., Yeh, S, Antes, M, Berkenpas, M, Davison, J 2007, ‘Use of experience curves to estimate the future cost of power plants with CO2 capture’, International Journal of Greenhouse Gas Control, Vol. 1, pp 188-197 Rubin, E.S, Chen, C, Rao, A.B 2007, ‘Cost and Performance of Fossil Fuel Power Plants with CO2 Capture and Storage’, Energy Policy, Volume 35, Issue 9, September 2007, pp 4444-4454. DOE/NETL 2010, Cost and Performance Baseline for Fossil Energy Plants, Volume 1: Bituminous Coal and Natural Gas to Electricity, Rev. 2, DOE/NETL-2010/1397, November 2010. Electric Power Research Institute (EPRI) 2007, CoalFleet RD&D Augmentation Plan for Integrated Gasification Combined Cycle (IGCC) Power Plants, Report no. 1013219, EPRI, Palo Alto, CA: January. Holt, N & Booras, G 2007, Updated Cost and Performance Estimates for Clean Coal Technologies Including CO2 Capture – 2006, EPRI Report No. 1013355, March 2007 Karg, Juergen 2009, IGCC Experience and Further Developments to Meet CCS Market Needs, Siemens AG report, September 2009



27

Technology cost improvement curves for the other scenarios were blended between these two extremes.

Projections for exchange rate variation, labour productivity variation and commodity index variation were kept common to those selected for the other technology cost curves.

Technology Description Integrated Gasification Combined Cycle

(IGCC) with CCS

Fuel Type Brown Coal, Latrobe Valley

Capital Costs A$/kW net 8616

Local Equipment / Construction Costs 21%

International Equipment Costs 52%

Labour Costs 27%

Engineering Procurement Contractors (EPC) costs

94%

Owners Costs (ref Section 4.2.5) 6%

Construction profile % of capital Cost Year 1 = 20% Year 2 = 60% Year 3 = 20%

First year available for Construction 2023

Typical new entrant size Gross/Net MW 936/550 MW

Economic Life >30 years; 50 years anticipated

Lead time for development (years) 10 years

Minimum stable generation level (% capacity) 50%

Thermal Efficiency (sent out – HHV) 25.5%

Thermal Efficiency (sent-out HHV) learning rate (% improvement per annum

0.55% Scenario 5 0.7% Scenario 1

Auxiliary Load MW / % 384MW / 41%

FOM ($/MW/year) for 2012 123,400 Based on factored up of GCCSI Economic Assessment of Carbon Capture and Storage Technologies report Based on factored up of GCCSI Economic Assessment of Carbon Capture and Storage Technologies report

FOM Escalation Rate (% of CPI) Refer Section 3.9

VOM ($/MWh sent-out) 2012 11 Based on factored up of GCCSI Economic



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Technology Description Integrated Gasification Combined Cycle (IGCC) with CCS

Assessment of Carbon Capture and Storage Technologies report.

VOM escalation rate (%of CPI) Refer Section 3.9

Percentage of emissions captured (%) 90%

Emissions rate per kgCO2e/MWh 151kg CO2e / MWh (Net)

Cost confidence level (based on source data accuracy to provide a % band or ranking for each technology)

+ / - 40%

5.2 IGCC plant with CCS based on bituminous coal

5.2.1 Technology description

An integrated bituminous coal gasification and combined cycle (IGCC) with carbon capture and storage (CCS) technology is similar to the IGCC plant with CCS based on brown coal. Bituminous coal is used in this type of technology. In Australia, this type of technology may be developed in either New South Wales or Queensland.

Based on the proposed Wandoan project, the capacity for IGCC with CCS based on bituminous coal is 400 MW.

Thermoflow software version 21 was used to model and derive the performance parameters for this technology including the capital cost. The cost factors used for Australian based models based on default values provided by the Thermoflow software were 1.3 for equipment and commodity and 2.025 for labour. As for brown coal fuelled IGCC, bituminous coal fuelled IGCC with carbon capture was modelled as for Brown coal ICGG-CCS, with two oxygen-blown, dry-feed, Shell gasifiers, convective cooling of the raw syngas, fuelling two GE 9F gas turbines. Capture and compression of CO2 from the syngas stream was modelled as an amine absorbent process taking place after the acid gas cleanup and water-gas shift stages of the syngas cleanup process. As for Brown coal IGCC, optimisation of the process my indicate variations such as Selexol process acid gas removal or other gasifier technology as having superior overall long run power generation costs.

5.2.2 Performance

The results of the plant performance modelling for this baseline configuration were a net plant output of 560 MW, and a net efficiency of 28.9% (Hunter Valley black coal basis). The net plant output and the net efficiency are lower than last year due to recent information on this technology reveals higher auxiliary load required than previously expected. As a result of the higher auxiliary load, the capital cost per unit of electricity generated ($/kWh) is higher than last year and the overall plant efficiency is lower. A minimum of 50% generation capacity is required to maintain a stable gasification process and effective gas cleaning. The total emission rate is 127kgCO2e / MWh sent out. The auxiliary load is



29

approximately 263 MW (including transformer losses), which is equal to 32% of the total generated power.


The capital cost split for Bituminous Coal IGCC with CCS is 21% commodity, 50% equipment and 29% labour. The high portion of capital cost apportioned to equipment cost leads to a large currency exchange rate exposure of future plant capital costs, as well as to non-exchange rate trends such as downward cost movement of technologies along a learning (or "Grubb") curve. Thus, if the Australian dollar remains strong such as would be characteristic for scenario 1, the downward cost trends of technology improvements would dominate, while if the Australian dollar weakens from its current position, as typical for the weak growth, the scenario 5 case, overall capital costs for IGCC black coal with CCS are expected to increase.


With respect to the curves estimating technological improvement over time, a similar technology improvement was assumed as for the Brown Coal IGCC-CCS cases, with the additional decline in capital cost of 12-17% over the otherwise steady cost improvement applied to account for a major improvement in the costs of carbon capture equipment. As for the Brown Coal IGCC-CCS, this improvement is expected in line with commercial deployment of such equipment following successful large scale demonstrations, which is forecast to commence at the earliest from around 2023 for the high growth scenario 1, or later, around 2025, for the low growth scenario 5. Intermediate scenarios were set with a similar change to commence in the years between these two cases.

As for the Brown Coal IGCC-CCS cases, the lack of reference plants results in a high degree of uncertainty about the deployed costs and timelines for this technology.

4 Rubin, E.S., Yeh, S, Antes, M, Berkenpas, M, Davison, J 2007, ‘Use of experience curves to estimate the future cost of power plants with CO2 capture’, International Journal of Greenhouse Gas Control, Vol. 1, pp 188-197 Rubin, E.S, Chen, C, Rao, A.B 2007, ‘Cost and Performance of Fossil Fuel Power Plants with CO2 Capture and Storage’, Energy Policy, Volume 35, Issue 9, September 2007, pp 4444-4454. DOE/NETL 2010, Cost and Performance Baseline for Fossil Energy Plants, Volume 1: Bituminous Coal and Natural Gas to Electricity, Rev. 2, DOE/NETL-2010/1397, November 2010. Electric Power Research Institute (EPRI) 2007, CoalFleet RD&D Augmentation Plan for Integrated Gasification Combined Cycle (IGCC) Power Plants, Report no. 1013219, EPRI, Palo Alto, CA: January. Holt, N & Booras, G 2007, Updated Cost and Performance Estimates for Clean Coal Technologies Including CO2 Capture – 2006, EPRI Report No. 1013355, March 2007 Karg, Juergen 2009, IGCC Experience and Further Developments to Meet CCS Market Needs, Siemens AG report, September 2009



30


Fuel Type Bituminous Coal, Hunter Valley


Local Equipment / Construction Costs (includes commodities)

21%


Labour Costs 27%

Engineering Procurement Contractors (EPC) costs

94%


Construction profile % of capital Cost Year 1: 20%

Year 2: 60%

Year 3: 20%


Typical new entrant size Gross/Net MW 821 / 560 MW

Economic Life >30 years


Minimum stable generation level (% capacity) 50



0.3% Scenario 5 0.6% Scenario 1

Auxiliary Load MW / % 263 MW or 32%

FOM ($/MW/year) for 2012 98,700 Based on factored up of GCCSI Economic Assessment of Carbon Capture and Storage Technologies report


VOM ($/MWh sent out) 2012 8 Based on factored up of GCCSI Economic Assessment of Carbon Capture and Storage Technologies report.

VOM Escalation Rate (% of CPI) Refer Section 3.9




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Emissions rate per kgCO2e/MWh 127 kgCO2e / MWh (Net) )


+ / - 40% (Estimated)

5.3 Supercritical Pulverised Coal (PC) Technology

5.3.1 Technology Description

Supercritical pressure units generate steam at pressures of at least 24.8 MPa with steam temperatures of 565-593°C. Supercritical units operate at about two percentage point’s higher efficiency than subcritical units (i.e., increasing from 36.5 to 38.5% efficiency on a higher heating value basis for plants with wet cooling towers).

For the PC cases evaluated in this report, there are two types of coal examined namely; Hunter Valley black coal and Latrobe Valley brown coal. Brown coal has very high moisture content and requires drying before it can be used. Owing to the high amount of water to be removed, the drying process requires a lot of energy and, therefore, energy efficiency in this process is very important.

Black coal does not require drying.

For supercritical plants the major components included in the cost for a pulverised brown/black coal-fired plant include coal-handling equipment, boiler or steam generator island, turbine generator island including all balance of plant (BOP) equipment, bottom and fly ash handling systems as well as emission control equipment. Particulate emissions are typically controlled using fabric filter electrostatic precipitator systems.

Supercritical PC plant configurations with CCS will include a post-combustion carbon capture technology such as an amine-based process. Absorption of CO2 in chemical solvents such as amines is a technology that has an excellent track record in many applications. The reaction between CO2and amines can offer a cost-effective solution for directly obtaining high purity CO2 for a capture efficiency of 90%. The CO2 rich solution at the top of the stripper is condensed and the CO2 phase is removed and sent off for drying and compression. The compression pressure was assumed to be of the order of 150 Bar.

An alternative PC coal technology considered in this report is the oxy-combustion system for CO2 capture. In this technology the fuel is combusted in a blend of oxygen and recycled flue gas which is in CO2. Recycling is achieved by looping the exhaust duct prior to the stack and redirecting the flue gas back to the boiler where it is mixed with a blend of oxygen and pulverised fuel. The flue gas recycle loop may include dewatering and de-sulphurisation processes. As a result, the flue gas downstream of the recycle slipstream take-off consists primarily of CO2 and water vapour (with small amounts of nitrogen, oxygen, and criteria pollutants). After the water is condensed, the CO2 rich gas is compressed and purified to remove contaminants and prepare the CO2 for transportation and storage.



32

The oxygen stream is produced in an air separation unit (ASU). This is a large system that consumes a considerable amount of electricity. In an effort to reduce its load and penalty on power output, new, more energy-efficient oxygen separation technologies are in development. In addition, the oxy-combustion plant will have additional flue gas treatment modules, several heat exchangers to extract low grade heat, and fans and ducts for flue gas recirculation (FGR).

Space must be provided for these, in addition to the CO2 capture hardware.

The battery limits for this technology and other fossil fuel technologies are shown in Appendix 2.

Thermoflow software version 21 was used to model and derive the performance parameters for these technologies including the capital costs. The cost factors used for Australian based models based on default values provided by the Thermoflow software were 1.3 for equipment and commodity and 2.025 for labour.


The major technical issues with advancing PC coal technology are mostly associated with new metal alloys as well as operating flexibility. As the technology further progresses, new materials will be required for higher temperature and pressures. This will require development of high chrome and nickel alloy pressure parts that can operate at temperatures in excess of 700ºC. The following figure illustrates the effect of increasing the steam conditions on improved overall plant efficiency.

5 Rubin, E.S., Yeh, S, Antes, M, Berkenpas, M, Davison, J 2007, ‘Use of experience curves to estimate the future cost of power plants with CO2 capture’, International Journal of Greenhouse Gas Control, Vol. 1, pp 188-197 Rubin, E.S, Chen, C, Rao, A.B 2007, ‘Cost and Performance of Fossil Fuel Power Plants with CO2 Capture and Storage’, Energy Policy, Volume 35, Issue 9, September 2007, pp 4444-4454. DOE/NETL 2010, Cost and Performance Baseline for Fossil Energy Plants, Volume 1: Bituminous Coal and Natural Gas to Electricity, Rev. 2, DOE/NETL-2010/1397, November 2010. Electric Power Research Institute (EPRI) 2008, CoalFleet Guideline for Advanced Pulverized Coal Power Plants, Version 3, EPRI, Palo Alto, CA: March. Holt, N & Booras, G 2007, Updated Cost and Performance Estimates for Clean Coal Technologies Including CO2 Capture – 2006, EPRI Report No. 1013355, March 2007



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Figure 4 Improvement in Heat Rate with Increasing Steam Conditions6

There are already plans to build a commercial-scale Supercritical PC facility with main steam temperature of 700ºC by 2016. There are current activities to develop and test materials needed to achieve main steam conditions of 760ºC and 34.5 MPa in boilers and steam turbines. It is expected and assumed that those conditions will be available in commercial-scale plants by 2030.

It is estimated that moving to 760ºC and 34.5 MPa will increase thermal efficiency by at least six percentage points compared to today’s technology.

While an increase in thermal efficiency does not directly impact on post-combustion capture processes, it does however mean that a more efficient power plant produces less CO2 per MWh.

Likewise a facility fitted with post combustion CO2 capture plants will need smaller CO2 capture systems due to the higher thermal efficiency. This will ultimately result in a decrease in the capital cost of CO2 capture on a $/kW basis, as well as decrease the auxiliary power load of the capture system.

In addition to improved Rankine cycle efficiency by increasing steam temperature and pressure, it is also assumed that post-combustion CO2 capture technology will improve significantly by 2030.

The current MEA based amine system is expected to improve significantly over the next several years and there are likely to be step changes in lower cost and higher efficiency processes for other CCS systems under development.

6 Source “Australian Electricity Generation Technology Costs – Reference Case 2010” Prepared by EPRI, February 2010.



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Advancement in CO2 compressor technology, with inter-cooling systems, will also lower the overall $/kW cost and reduce the auxiliary loads needed to run the CCS plant.

For the cases involving brown coal, it is expected that new coal drying technologies, using low grade heat, will be used to dry the coal more efficiently.

The anticipated PC, Post Combustion Capture and Oxy Combustion performance and cost improvements by 2030 as recently published in the report entitled “Australian Electricity Generation Technology Costs – Reference Case 2010” prepared by EPRI are:

Black Coal CCS Brown Coal CCS Black Coal Oxy

2030 Technology 2030 Technology 2030 Technology

Capex (Relative to current technology)

0.81 0.83 0.80

Thermal Efficiency 10.1 Pts 12.5Pts 8.0Pts



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5.3.3 Pulverized Coal Supercritical Brown Coal with CCS

Technology Description Pulverised Coal supercritical with CCS Fuel Type Brown Coal – Latrobe Valley Capital Costs A$/kW net 7766 Local Equipment / Construction Costs (includes commodities)

36%

International Equipment Costs 35% Labour Costs 29% Engineering Procurement Contractors (EPC) costs 91% Owners Costs (ref Section 4.2.5) 9% Construction profile % of capital Cost Year 1 = 35%

Year 2 = 35% Year 3 = 20% Year 4 = 10%

First year available for Construction 20237 Typical new entrant size Gross/Net MW 750 / 569 MW Economic Life 50 years Lead time for development (years) 10 years Minimum stable generation level (% capacity) 40% Thermal Efficiency (sent out – HHV) 21% Thermal Efficiency (sent-out HHV) learning rate (% improvement per annum

Auxiliary Load MW / % 181MW / 24% FOM ($/MW/year) for 2012 $91,500/MW/year

Based on factored up of GCCSI Economic Assessment of Carbon Capture and Storage Technologies report

FOM Escalation Rate (% of CPI) Refer section 3.9 VOM ($/MWh sent out) 2012 $15/MWh VOM Escalation Rate (% of CPI) Refer section 3.9 Percentage of emissions captured (%) 90% Emissions rate per kgCO2e/MWh 156 kgCO2e / MWh (Net) Cost confidence level (based on source data accuracy to provide a % band or ranking for each technology)


7 For supercritical with CCS, the first year of construction for a new entrant incorporating a full scale carbon capture production plant transporting and storing CO2 efficiently and effectively, will be approximately 2023 with commercial operation in 2025. CCS technology is still in pilot phase in Australia and all aspects of the capture, transport and storage need to be proven first at scale over the coming years.



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5.3.4 Pulverised Coal Supercritical Bituminous Coal with CCS Technology Description Pulverised Coal Supercritical with CCS

Fuel Type Bituminous Coal – Hunter Valley

Capital Costs A$/kW net 5,110

Local Equipment / Construction Costs (includes

commodities)

35%


Labour Costs 28%

Engineering Procurement Contractors (EPC)

costs

91%


Construction profile % of capital Cost Year 1 = 35%

Year 2 = 35%

Year 3 = 20%

Year 4 = 10%


Typical new entrant size Gross/Net MW 750 / 577 MW

Economic Life 50 years



Thermal Efficiency (sent out – HHV) 29%

Thermal Efficiency (sent-out HHV) learning rate

(% improvement per annum

Auxiliary Load MW / % 173 MW / 23 %

FOM ($/MW/year) for 2012 $73,200/MW/year Based on factored up

of GCCSI Economic Assessment of

Carbon Capture and Storage

Technologies report



37

Technology Description Pulverised Coal Supercritical with CCS


VOM ($/MWh sent out) 2012 $12/MWh



Emissions rate per kgCO2e/MWh 110kgCO2e / MWh (Net)

Cost confidence level (based on source data

accuracy to provide a % band or ranking for each

technology)


5.3.5 Oxy-Combustion Pulverised Coal Supercritical Bituminous Coal with CCS

Technology Description

Oxy Combustion Supercritical

Fuel Type Bituminous Coal – Hunter Valley


Local Equipment / Construction Costs (includes commodities) 32% International Equipment Costs

35% Labour Costs

33% Engineering Procurement Contractors (EPC) costs 93% Owners Costs (ref Section 4.2.5)

7% Construction profile % of capital Cost

Year 1 = 35%

Year 2 = 35%

Year 3 = 20%

Year 4 = 10% First year available for Construction

2022 Typical new entrant size Gross/Net MW

750 / 554 MW Economic Life

50 years Lead time for development (years)

10 years Minimum stable generation level (% capacity)

80% Thermal Efficiency (sent out – HHV)

32.5%

8 Based on recirculating system not being able to sustain a high turn down ratio.



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Thermal Efficiency (sent-out HHV) learning rate (% improvement per annum Auxiliary Load MW / %

196 MW / 26 FOM ($/MW/year) for 2012

$62000/MW/year FOM Escalation Rate (% of CPI)

Refer section 3.9 VOM ($/MWh sent out) 2012

$14/MWh VOM Escalation Rate (% of CPI)

Refer section 3.9 Percentage of emissions captured (%)

100%9 Emissions rate per kgCO2e/MWh

010 Cost confidence level (based on source data accuracy to provide a % band or ranking for each technology)


5.4 CCGT Technology based on natural gas Technology Description

In Australia’s immediate future, it is expected that the power generation industry will utilize gas turbines as the basis for the majority of new fossil fuel power stations. There are various types and categories of gas turbines available in the market today that are suitable to the power generation industry. These include the earlier designed E class and the state-of-the-art heavy-duty F, G and H class turbine models; all of which are suitable for CCGT applications. These gas turbines are available in certain given ratings.

Their efficiencies depend on several factors such as inlet mass flow, compression ratio and expansion turbine inlet temperature. Recent state-of-the-art heavy-duty gas turbine designs have advanced hot gas path materials and coatings, advanced secondary air cooling systems, and enhanced sealing techniques that enable higher compression ratios and turbine inlet temperatures that reach over 1,371°C.

A CCGT plant based on natural gas uses a combination of a natural gas fired turbo-generator system, a Heat Recovery Steam Generator (HRSG) and a steam turbo-generator system to provide power. Combined cycle plants can operate with both the lower class of gas turbines and the advanced class gas turbines. The combined cycle gas turbine facility can be built up from the discrete size gas turbine(s). The HRSG and steam turbine are sized to utilise the exhaust energy available from the gas turbine(s) in order to maximise the recoverable energy from the gas turbine exhaust. There are various configurations of combined cycles with various numbers of HRSG reheat levels corresponding to different pressures.

The trend for large (700 MW) CCGT plants for base load operations is to utilise two gas turbogenerators along with two triple pressure reheat HRSGs and one steam turbogenerator. A small

9 Theoretically there would be zero CO2emissions from the plant, due to the oxy-combustion cycle being a closed loop with an installed CO2 cleaning plant. 10 See above.



39

plant (200-400 MW) typically only has one gas turbogenerator, its associated HRSG and one steam turbogenerator.

A CCGT plant with Carbon Capture and Storage (CCS) is based on the same technology as a CCGT plant with the addition of a system after combustion to capture carbon dioxide to prevent its release to atmosphere.

The addition of a CCS system on a CCGT is not common as the flue gas from a CCGT contains less CO2 than coal fired supercritical plants (CO2 concentration in a combined cycle plant’s flue gas is only around four per cent compared to 12 to 15% for coal). In addition, the flue gas flow is typically 50% greater than supercritical coal fired plants per megawatt of capacity due to ambient air being used as the compressible medium by the gas turbine. This higher flow in conjunction with the lower CO2 concentration could double the cost per tonne of capturing carbon comparable to a similar sized coal fired station. The increase in capture costs is offset however due to the smaller plant required for the CCGT case and the corresponding higher efficiency of a CCGT plant. It is expected that the capital cost of a CCS plant for a CCGT system will be lower than a comparably sized coal fired station.

There are systems utilised at pilot scale on coal fired plants in Australia to capture carbon dioxide. To date, there are no CCS systems used on CCGT’s in Australia. The most current and feasible systems to use on combined cycle plants are based on an amine absorption process where an amine solvent is used to strip the flue gas of CO2.

Large scale storage of the captured and compressed CO2 is still an unproven technology in Australia with geo-sequestration being the current most feasible solution. Suitable sites for the sequestration have been identified, however the effectiveness and economic efficiency have yet to be determined for this technology and will require significant research and development before it can be considered a proven method in Australia.

Expected Technological Improvement11

Combined cycle technology is a mature generating technology.

Improvements in efficiency and reductions in capital costs are not likely to be as extreme as an emerging technology. Future combined cycle plants will be based on advanced heavy-duty gas turbines which are expected to operate at higher firing temperatures and higher pressure ratios than current.

With these advanced gas turbines a more efficient reheat steam turbine cycle can also be selected for higher efficiency for the bottoming cycle. With these newer machines and upgraded materials (new alloys for pressure parts in HRSGs), combined cycle efficiencies can approach 60% (HHV basis).

11 Rubin, E.S., Yeh, S, Antes, M, Berkenpas, M, Davison, J 2007, ‘Use of experience curves to estimate the future cost of power plants with CO2 capture’, International Journal of Greenhouse Gas Control, Vol. 1, pp 188-197 Rubin, E.S, Chen, C, Rao, A.B 2007, ‘Cost and Performance of Fossil Fuel Power Plants with CO2 Capture and Storage’, Energy Policy, Volume 35, Issue 9, September 2007, pp 4444-4454. DOE/NETL 2010, Cost and Performance Baseline for Fossil Energy Plants, Volume 1: Bituminous Coal and Natural Gas to Electricity, Rev. 2, DOE/NETL-2010/1397, November 2010. Karg, Juergen 2009, IGCC Experience and Further Developments to Meet CCS Market Needs, Siemens AG report, September 2009



40

CCGT with CCS is still an emerging technology. The current MEA based amine system is expected to improve significantly over the next several years and there are likely to be step changes in lower cost and higher efficiency processes for other CCS systems under development. Advancement in CO2 compressor technology, with inter-cooling systems, will also work towards reducing the overall $/kW capital cost and reducing the auxiliary loads needed to run the CCS plant.

The percentage of emissions captured is claimed by the manufacturers of the technology to be as high as 98% for laboratory conditions; however in practice a capture rate of 85-90% is a more realistic number for power generation applications based on current experience.

5.4.1 CCGT based on natural gas without CCS

Thermoflow software version 21 was used to model and derive the performance parameters for this technology including the capital cost. The cost factors used for Australian based models based on default values provided by the Thermoflow software were 1.3 for equipment and commodity and 2.025 for labour. A cost estimate of A1,062 $/kW was used as the starting point for a 374 MW (net) CCGT plant built in 2013. The capital cost was estimated from a plant modeled on a single Siemens SGT5 4000F (F Class) gas turbine with a three pressure reheat HRSG. The plant has an installed capacity of 386 MW.


CCGT without CCS Fuel Type

Natural Gas Capital Costs A$/kW net

1,062 Local Equipment / Construction Costs (includes commodities)

18%


Labour Costs 26%

Engineering Procurement Contractors (EPC) costs 95%


Construction profile % of capital Cost 1st year – 60%

2nd year – 40% First year available for Construction

As CCGT plants are a mature technology, the first year available for construction of a new plant in all regions of the NTNDP is 2013, estimated from the current outlook.

Typical new entrant size MW gross/net 374 / 386 MW




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Technology Description CCGT without CCS




Thermal Efficiency (sent-out HHV) learning rate (% improvement per annum)

0.25%

Auxiliary Load (%) 3%

FOM ($/MW/year) for 2012 10,000

FOM Escalation Rate (% of CPI) Refer section 3.9

VOM ($/MWh sent out) 2012 4 12

VOM Escalation Rate (% of CPI) Refer section 3.9

Percentage of emissions captured (%) 0

Emissions rate per kgCO2e/MWh 357 (Gross) / 368 (Net)


+/- 30%

5.4.2 CCGT based on natural gas with CCS Thermoflow software version 21 was used to model and derive the performance parameters for this technology including the capital cost. The cost factors used for Australian based models based on default values provided by the Thermoflow software were 1.3 for equipment and commodity and 2.025 for labour. A cost estimate of $A2,772/kW (real 2012) was used as the starting point for a 327 MW (net) CCGT plant with CCS with construction starting in 2023. The capital cost was estimated from a modeled plant based on a single Siemens SGT5 4000F (F Class) gas turbine, with three pressure reheat HRSG. The plant had an installed capacity of 361 MW, and the CCS plant was sized to the plant and had 85% capture efficiency. Technology Description

CCGT with CCS

Fuel Type Natural Gas



14%


12 The operation and maintenance costs expressed excludes both the cost of fuel and carbon emissions as a variable operating cost.



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Technology Description CCGT with CCS

Labour Costs 19%

Engineering Procurement Contractors (EPC) costs 94%


Construction profile % of capital Cost 1st year – 60%

2nd year – 40%

First year available for Construction For a CCGT with CCS, the first year of construction for a new entrant incorporating a full scale carbon capture production plant transporting and storing CO2 efficiently and effectively, will be approximately 2023 with commercial operation in 2025.

CCS technology is still in pilot phase in Australia and all aspects of the capture, transport and storage need to be proven first at scale over the coming years.

Typical new entrant size (gross/net) 361/ 327 MW

Economic Life 40-50years





Auxiliary Load (%) 10%14

FOM ($/MW/year) for 2012 17,000

FOM Escalation Rate (% of CPI) Refer section 3.9 VOM ($/MWh sent out) 2012

915 VOM Escalation Rate (% of CPI)

Refer section 3.9 Percentage of emissions captured (%)

85%

14 Attributed to the compressor needed to compress the captured CO2 for storage and transport, as well as the extra cooling capacity needed by the CCS process required to increase the capture efficiency 15 The operation and maintenance costs expressed excludes both the cost of fuel and carbon emissions as a variable operating cost.



43

Technology Description CCGT with CCS

Emissions rate per kgCO2e/MWh 55 (Gross) / 60 (Net)


+/- 40%

5.5 Solar Thermal Technologies

5.5.1 Description of Technology - Solar Thermal

Solar thermal technologies use sunlight to heat a medium, and then use that medium to drive a power generation system. By using mirrors, the sun’s energy can be concentrated up to approximately 1,000 times. The concentrated sunlight is then focused onto a receiver containing a gas or liquid that is heated to high temperatures and used to generate steam that is delivered to a steam turbine that generates power.

Solar thermal technologies that will be investigated in this report are compact linear Fresnel, parabolic trough and central receiver tower. These systems are based on the concept of concentrating direct normal irradiation to produce steam used in electricity generating steam turbine cycles.

In these technologies the solar power generating systems use glass mirrors that continuously track the position of the sun while absorbing its solar radiation energy. The absorbed solar energy can be harnessed and transferred in two ways: directly or indirectly. The direct method circulates water directly through the concentrated solar radiation path, thus directly producing steam.

The indirect method uses a heat transfer fluid which absorbs solar radiation energy and transfers the heat to water by way of a series of solar steam generator heat exchangers, thus indirectly producing steam.

5.5.2 Compact Linear Fresnel Technology

CLFR technology provided by AREVA has been selected for the solar thermal solar flagship project. The project is based on using direct steam generation in the solar absorbers. The plant consists of 2 off 125 MW facilities. No energy storage is provided. It is expected that the proposed project will commence operation in 2015 following the finalisation of project development in December 2011 and a three-year construction timeframe.

Public information regarding the project has provided the following information:

• Capital Cost A$1.2 billion (A$4.8 million/MW)

• Capacity Factor 22% to 24%.

The Kogan Creek Solar Boost project has published the following data:

• Capital Cost A$104.3 million



44

• 44 MWe

The following picture shows a typical CLFR collector. The salient features are:

• A fixed elevated collector

• A series of flat mirrors reflecting sunlight onto the collector.

No learning allowance is applied for the next generation CLFR as the Kogan Creek and Solar Dawn plants are not yet installed and no operating / cost data of a built plant is available at these scales.



45

Technology Description Compact Linear Fresnel Technology – Direct Steam Generation – No storage

2 x 125 MW gross Fuel Type Solar


Local Equipment / Construction Costs (includes

commodities) 25%


Labour Costs 20%

Construction profile % of capital Cost Year 1 50% Year 2 30%

Year 3 20%


Typical new entrant size 125 MW unit size


Lead time for development (years) 4

Minimum stable generation level (% capacity) 10% - Output is dependent on solar resource

– no energy storage in this case

Thermal Efficiency (sent out – HHV) 22% to 24%

Thermal Efficiency (sent-out HHV) learning rate (%

improvement per annum Refer Section 5.5.5


FOM ($/MW/year) for 2012 50,000 – 70,000


VOM ($/MWh sent out) 2012 0 - 3018


Percentage of emissions captured (%) Not Applicable

Emissions rate per kgCO2e/MWh Not Applicable

18 A range of industry specialists (references “NREL Cost and Performance Assumptions for Modelling Electricity Generation Technologies, November 2010”, “CRS Report for Congress – Power Plants: Characteristics and Cost, November 2008”, “NREL Potential for Renewable Energy in the San Diego Region, August 2005” and “GTM Research Cost and LCOE by Generation Technology, 2009-2020”) have assessed the prime O & M cost for solar thermal plant as being of a fixed nature. This comprises fixed staffing, fixed service provider costs and fixed maintenance, inspection and repair services. Variable O & M cost per MWh sent out ranges from 0 to $30 in their assessment. With capacity factors limited by daylight, cloud and weather constraints being region and site dependent but typically less than 40%, the fixed O & M component greatly impacts the total O & M cost per MWh of output.



46

Technology Description Compact Linear Fresnel Technology – Direct Steam Generation – No storage

2 x 125 MW gross


+/- 40%

5.5.3 Parabolic Trough Technology

Parabolic trough is the most widely deployed solar thermal technology with the first plants being installed in the 1980’s in the US.

A typical parabolic trough system is shown below:



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Technology Description Solar parabolic trough – indirect heating utilising heat transfer fluid and oil / steam heat exchangers. Storage utilising molten salt storage tanks. 150 MW capacity

Fuel Type Solar



20%


Labour Costs 25%

Construction profile % of capital Cost Year 1 50%

Year 2 30%

Year 3 20%


Typical new entrant size 150 MW

Economic Life 30-40 years



Capacity Factor 42%


Refer Section 5.5.5


FOM ($/MW/year) for 2012 50,000-70,000


VOM ($/MWh sent out) 2012 0-30




19 Based on a solar field multiplier of 2. The solar field multiplier refers to the oversizing of the solar field compared to the turbine output so that energy can be stored and released.



48

Technology Description Solar parabolic trough – indirect heating utilising heat transfer fluid and oil / steam heat exchangers. Storage utilising molten salt storage tanks. 150 MW capacity


+/- 40%

5.5.3.1 CAPITAL COST BREAKDOWN

The following figure is based on a 50 MW plant with seven hours storage. A similar split of costs is assumed for the 150 MW plant capacity.

Figure 5 : Capital Cost Breakdown(Source IEA 2010 Report: Technology Roadmap Concentrating Solar Power)

The apportionment of costs is as follows:

Item Local (%) International (%)

Solar Field 10 20



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Item Local (%) International (%)

Allowances 7 7

Storage 5 4

Project Management 5 3

Balance of Plant 3 5

Civil Works 7

Power Block 5

Heat Transfer Fluid 5

Project Development 3

Miscellaneous 1 1

Total 41 50

Total (converted to 100%) 45 55

5.5.4 Central Receiver Technology

The Gemasolar central receiver system is shown in the figure below.

Gemasolar is the first commercial-scale plant in the world to apply central tower receiver and molten salt heat storage technology. The relevance of this plant lies in its technological uniqueness, since it opens up the (thatway for new thermosolar electrical generation technology.



50

Characteristics of Gemasolar:

• Rated electrical power: 19.9 MW

• Net electrical production expected: 110 GWh/year

• Solar field: 2,650 heliostats on 185 hectares

• Heat storage system: the molten salt storage tank permits independent electrical generation for up to 15 hours without any solar feed

• Capital Cost 200M Euro.

For this analysis, six hours storage is required which will reduce the solar field, storage capacity and associated equipment in the order of 40% with an expected impact on capital of around 70% - resulting in a reduction of 30% compared with Gemasolar. For a commercial plant with the learning’s from Gemasolar a further cost reduction of 20% is allowed in the expected capital cost.


Solar Tower – Central Receiver with 6 hours storage

Fuel Type Solar



20%


Labour Costs 25%

Construction profile % of capital Cost Year 1 50%

Year 2 30%

Year 3 20%





Minimum stable generation level (% capacity)Capital Costs A$/kW net

10%8,308

Capacity FactorLocal Equipment / Construction Costs (includes commodities)

42%20%


Refer Section 5.5.5



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Technology Description Solar Tower – Central Receiver with 6 hours storage


Auxiliary Load (%)Labour Costs 10%25%

FOM ($/MW/year) for 2012Construction profile % of capital Cost

50,000 – 70,000Year 1 50%

Year 2 30%

Year 3 20%

FOM Escalation Rate (% of CPI)First year available for Construction

Refer section 3.92016

VOM ($/MWh sent out) 2012Typical new entrant size

1-03020 MW

VOM Escalation Rate (% of CPI)Economic Life Refer section 3.940 years

Percentage of emissions captured (%)Lead time for development (years)

Not applicable4 years

Emissions rate per kgCO2e/MWhMinimum stable generation level (% capacity)

Not applicable10%

Cost confidence level (based on source data accuracy to provide a % band or ranking for each technology)Capacity Factor

+/- 50%42%


Refer Section 5.5.5


FOM ($/MW/year) for 2012 50,000 – 70,000


VOM ($/MWh sent out) 2012 1-030

5.5.5 Solar Thermal Future Improvements

As concentrating solar power plants gain footing in the utility market and their installed capacity expands, the cost of the plants is expected to continue to decrease due to the higher production volume of key equipment and increased experience gained by manufacturers and engineers who are planning and building plants.

In addition, it is expected that cheaper heat transfer fluids will become available or that fluids that can handle higher temperatures, and therefore increase efficiency, will be used. The cost of storage systems is also expected to be reduced.



52

Furthermore, improvements are expected in receiver tube absorption and steam turbine efficiencies that would increase the capacity factor for these plants. The combination of a decrease in capital cost and an increase in plant output will lead to a lower cost of electricity. An overview of the anticipated capital cost improvements by technology is presented in the table below.

Parabolic Trough Central Receiver/Linear Fresnel

With 6hs Storage

Without Storage With 6hrs Storage

Without Storage

Capex (Relative to 2015 technology)

0.70 0.65 0.65 0.60

Each of the solar thermal technologies are at a different stage of development.

Currently, the most mature technology is the parabolic trough, which is at the commercial phase. Central receiving towers have been demonstrated and are ready for scale up and commercialisation. It is expected that development and/or further refining of these systems for power generation will continue well into the 2025-2030 timeline.

5.6 Photovoltaic PV Fixed Flat Plate

Solar photovoltaic (PV) technologies convert sunlight directly into electricity using semiconductor materials that produce electric currents when exposed to light. Semiconductor materials used for PV cells are typically silicon mixed with other elements that have either one more or one less valence electrons to alter the conductivity of the silicon.

PV technology can be installed as fixed flat plates on roofs or a large field and can be mounted on tracking devices that have single axis and two axis tracking.

PV technology is still evolving and although already fully commercialized, is only gradually emerging from the shelter of government subsidies through manufacturing/installation subsidies and various power market share mandates such as LRET/MRET. There have been significant increases in solar PV installation in recent years with significant price reductions / kW as large scale manufacturing facilities allow minimization of production costs.

The cost of electricity from photovoltaic plants is expected to decrease rapidly in the future, as it has done with expanded manufacturing capacity and increased manufacturing process and cell efficiencies. This is due both to expected reduction in solar panel costs and increased efficiency. The balance of system and inverter costs is also expected to decrease over time. Research has continued to develop new PV configurations, such as multi-junction concentrators, that promise to increase cell and module efficiency.



53

A number of recent reports were utilized in providing the basis for the sizing and costs associated with the PV fixed plate. The reports are USA based and provide information with regard to recent utility scaled projects based on publically available information together with proposed technology advancement / cost reduction programs.

5.6.1 The Berkeley Report20

The Berkeley report provides the following key points:

• There was a wide range of installed cost / MWDC for the 20 utility scale projects investigated. The causes of a wide range include differing project size, different PV modules (thin film / crystalline), fixed or tracking configuration;

• Cost typically declines with increasing size;

• Thin film technology is typically lower cost than crystalline technology;

• A number of cited sources have provided installed cost benchmarks in US$ DC power rating of between $3.8 and $4.1 per watt for large scale utility projects; and

• There is project evidence that utility scale costs have reduced significantly over the period of 2008 to 2010.

5.6.2 US DOE $1/Watt program

The United States Department of Energy (DOE) has recently (in 2010) implemented a program with the aim of achieving installed solar photovoltaic for $1/Watt by 2017.

With the current rate of progress, the cost of utility‐sized photovoltaic (PV) systems is predicted to reach $2.20/watt by 2016.

The DOE has also identified that it is unlikely to be able to sustain continued price reductions without significant ongoing investment. The cost reductions are considered across three main areas of utility project development as tabulated below.

All costs are in USD.

2010 2016 $1/Watt aim

Module 1.70 1.05 0.50

BOS 0.91 0.97 0.40

Installation 0.57

Power Electronics 0.22 0.18 0.10

20 Tracking the Sun I 58 V: The Installed Cost of Photo Voltaics in the US from 1998 – 2010: Galen Barbose / Naim Darghouth / Ryan Wiser / Joachim Seel, September 2011 Lawrence Berkeley National Laboratory



54

2010 2016 $1/Watt aim

Total 3.40 2.20 1.00

Operations & Maintenance $US/kWh

0.013 0.009 0.003

5.6.3 Capital Cost basis

Based on the US information presented above the cost basis proposed for 2012 is based on the following:

• 2010 cost range midpoint $3.95/W DC

• For 2012 use a 6% cost reduction equating to $3.72/W DC

• Factor to convert to W AC – use multiplier of 1.15 for the DC components (solar field) based on WorleyParsons project experience, i.e. 1.15 W DC installed converts to 1W AC (the solar module field is oversized compared to the inverter AC size)

• Costs do not include step up transformer and switching station typically within plant boundary – allow $0.15/W DC for this cost based on recent WorleyParsons experience

• Assume A$1 = US$1

Total Installed Cost within plant boundary $3.87/W DC / $4.27/W AC



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Technology Description 100MW AC c-SI fixed photovoltaic plant

Fuel Type Solar



15%


Labour Costs 15%

Construction profile % of capital Cost Year 1: 70%

Year 2: 30%

First year available for Construction Available for construction for 2012. Estimate for a project to achieve commercial operation based on a 2012 start is 2015 – based on a three year allowance for permitting, finance, engineering, procurement and construction.

Typical new entrant size Can be any size and can be built on over time. Basis is for a nominal 100MW AC plant.

Economic Life 30-40 years


Minimum stable generation level (% capacity) Non despatchable. Generation level is dependent on solar resource. No energy storage is included in this analysis

Thermal Efficiency (sent out – HHV) Not applicable


Reduction in capital cost as follows:

2012 – 2022 : 3% per year

2013 – 2038 : 2% per year

2029 – 2032 : 1 % per year

Capacity Factor (AC Output basis) Melbourne 15%

Adelaide 17.5%

Canberra 18%

Sydney 16.2%

Brisbane 17.5%



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Technology Description 100MW AC c-SI fixed photovoltaic plant

Auxiliary Load (%) Nil

FOM ($/MW/year) for 2012 $38,000/MW AC/year21

FOM Escalation Rate (% of CPI) 100%

VOM ($/MWh sent out) 2012 Included in FOM – minimal variable O&M Costs with this technology

VOM Escalation Rate (% of CPI) Included in FOM




+ / - 40%

The following cost split is from the USDOE $1/W White Paper and provides the basis for capital cost split. The BOS / Installation are considered to be split equally between labour, local procurement and imported equipment with all modules and inverters imported.

Figure 6 : Basis for Capital Cost Split

21 Based on recent WorleyParsons’ experience – significantly affected by proposed manning level and basis for inverter change-out interval and panel degradation and life



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5.7 Wind Technology


On-shore wind generation represents the most mature form of renewable energy generation technology. Whilst there are a number of variations on the technology, the vast majority of recent installations globally are of a standard configuration, consisting of a tower mounted three blade up-wind turbine design. Utility scale wind farms typically utilise machines in the 1 to 3 MW range with hub heights 70 to 100m, rotor diameters of 70 to 120m. Wind farms are typically arrays of 50 to 150 turbines.

The passage of the wind over the rotor drives a generator housed in the “nacelle” on the top of the tower. The two primary generator configurations are a direct drive ring or annular generator, or more commonly, a transmission driven high speed generator. Transformers located within the nacelle or at the base of the tower then transform the power for distribution to the power collection system. One or more substations then collect the reticulated power and transform to the correct network voltage for export to the electrical distribution or transmission system.

5.7.2 Wind Resource

Whilst wind generation has a zero cost fuel source, the quality of the wind resource has a significant impact on the delivered cost of energy from a wind turbine. There are a number of factors that impact the quality of the wind resource, including

• Wind speed – Energy output is related to wind speed by a cubic relationship. Thus energy production is significantly influenced by wind speed. Whilst wind speed provides a measure of the energy available for generation, a higher wind speed may not always produce an optimal energy yield from a wind generation plant. Turbines are designed to specific wind regimes (i.e. class of machine), and lower wind speeds enable larger rotor areas for a given generator, thus enabling good energy extraction and capacity factor from a moderate wind resource

• Turbulence – Turbulence of the wind resource influences the energy yield from a machine in two ways. Firstly, turbulence will directly reduce energy conversion due to the plane of the rotor not being optimally perpendicular to the wind flow direction. Secondly, high turbulence can have an impact on the operational cost and availability of a machine due to excessive wear and breakage of components.

• Wind shear – wind shear conditions can vary considerably on a site by site basis. Wind shear is an indication of the velocity profile of the wind with elevation. The shear at a site can vary considerably on a diurnal cycle, and can vary from a high speed gain with elevation to cases of negative shear where wind speed reduces with elevation. An understanding of the shear profile is thus important in site selection and resource assessment.

• Time profile – Variance of wind resource on a site can be measured across a number of time scales. For system operation and stability issues, short time frame performance tends to be important, while longer time frame performance (daily to annual) tends to dominate with network and market issues. Wind resource will generally have a diurnal (or daily) weighting, which may vary across the year. Seasonal variation is also generally quite pronounced. It is important to



58

understand these characteristics for a site in order to establish the interaction of the generation with the network and market.

For the purposes of modelling a baseline 100 MW wind farm, a moderate wind resource with a capacity factor of 38% from the plant has been assumed. Turbulence and wind shear are also assumed to be within tolerance of the machines resulting in an average O&M profile.


The capital cost split for the 100 MW wind farm case has 26% commodity, 59% specialised equipment, 11% labour and 4% engineering and overhead. Similar comments with respect to the sensitivity of these capital portions to the external parameters of exchange rate, productivity and commodity indices apply.

5.7.4 Capital Costs

While the generation technology configuration is relatively stable, there have been a number of significant advances in the capacity of the machines that have resulted in improved LCOE over the past decade. It is expected that advances in a number of areas will continue to drive the capital cost down into the forecast period. The IEA projections22 incorporate a learning rate of 7%, while the European Wind Energy Association (EWEA) are forecasting a 10% learning rate consistent with that observed historically23 (the learning rate implies that each time the total installed capacity doubles, the costs per kWh of wind generated power decreases by the learning rate). EWEA forecasts that the installed capacity will double every 3 years over the forecast period 23, providing a decrease in technology cost. A shorter term reduction in capital as a result of the increase in market share of Chinese imported turbines has also been included.

The principal areas of development of technology resulting in increased output efficiency are expected to include:

• Materials: stronger and lighter materials are expected to allow the development of larger and lighter blades

• Electrical Efficiency: increase in electrical efficiency due to the introduction of super conductor materials

The trend in turbine design over the past two decades has seen the consistent development of larger turbines, which is likely to continue into the future. Material and construction technique developments enable the use of taller towers and larger diameter rotors, which have the benefit of improving the energy capture through accessing stronger and less turbulent wind at higher elevations as well as increasing the energy intercepted from the swept area of the rotor.

Likely areas developments in the technology over the next decade include;

22 International Energy Agency and Nuclear Energy Agency (2010), Projected Costs of Generating Electricity 2010 Edition, Organization forEconomic Cooperation & Development, France 23 European Wind Energy Association (200 9), Economics of Wind Main Report, European Wind Energy Association. Available at: http://www.ewea.org/fileadmin/ewea_documents/documents/publications/reports/Economics_of_Wind_Main_Report_FINAL-lr.pdf



59

• Lighter and longer blades, increasing the capital efficiency of the design (IEA anticipate blade lengths of up to 125m by 2020)

• Improvements to the drive train, including a reduction in the fixed losses during low power conditions, and improvements in the design of both gearboxes and annular generators

• New tower material and erection technologies leading to taller towers at lower costs. Associated reductions in generator and transmission weight will reduce the structural requirements of the tower

5.7.5 Internationally Sourced Equipment Costs

At present there is no source for locally manufactured wind turbines in Australia. In the past there were facilities established to assemble machines, and there have been a number of attempts to establish blade manufacturing in Australia. The local assembly plant has now stopped operation, and all turbine generation equipment is sourced internationally (primarily from Europe and India to date). The balance of plant (including the towers) is generally sourced on shore in Australia, although some specialised items associated with the HV power and communications may be sourced internationally.

The international component of turbine supply is estimated at of 63% of the total project capital. As discussed, the primary source of equipment to date has been Europe and India, although there is expected to be an increasing proportion of equipment imported from China over the forecast period.

5.7.6 First Year Available for Construction

Wind farms have an operating history in Australia of over 20 years, with MW class machines having been deployed in Australia for over a decade. Development time for a typical wind farm project is in the order of four to seven years from site identification to operation.

5.7.7 Typical New Entrant Size

WorleyParsons has considered the economics of a 100 MW wind farm in this report. 100 MW is considered an average size for new wind farms, with a trend towards larger facilities continuing in Australia over the past decade. Wind farm size tends to be limited by the following factors:

• Availability of network capacity (ie limitation of upgrade and augmentation costs associated with a larger wind farm)

• Availability of sufficient land area. Depending on the planning jurisdiction, land area can be constrained by setbacks from dwellings and sensitive environmental areas

• Availability of wind resource. In many wind farms, the necessary wind resource is limited to specific topographic features (e.g. ridge tops) which will the limit the project size

• Ability to secure off-take.

There is an increasing trend to progress larger scale projects, with the recent 400MW Macarthur Wind Farm being an example. It expected that 100+ MW wind farms will become more common over the forecast period with an ongoing trend towards deployment of fewer, larger capacity machines.



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5.7.8 Operations and Maintenance

Due to the relative infancy of the wind energy industry, there are only a few turbines that have reached their life expectancy of 20 years. These turbines are much smaller than those currently available on the market.

Estimates of O&M costs are still highly unpredictable, especially around the end of a turbine’s lifetime; nevertheless a certain amount of experience can be drawn from existing older turbines.

Based on experiences in Germany, the UK and USA, O&M costs are generally estimated to be around 1.2 to 1.5 euro cents (c€) per kWh of wind power produced over the total lifetime of a turbine24.

A cost profile for variable and fixed operations and maintenance costs (with an average annual cost in the order of 1.4 euro cents (c€) per kWh) has been derived, based on the following assumptions:

1. Assumes fixed O&M contract for first two years 2. Data shape according to Albers (WindGuard) 3. Data are estimates only and may vary significantly between turbines types/makes/models &

contracts used 4. Assumes a capacity factor of 38%.

Figure 7 : Wind Farm VOM ($/MWh)

24 European Wind Energy Association (200 9), Economics of Wind Main Report, European Wind Energy Association. Available at: http://www.ewea.org/fileadmin/ewea_documents/documents/publications/reports/Economics_of_Wind_Main_Report_FINAL-lr.pdf

0

5

10

15

20

25

0 5 10 15 20 25

VOM

($/M

Wh)

Operating Year

100 MW Wind Farm: VOM ($/MWh)



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Figure 8 : Wind Farm FOM ($/MW AC/year)

Technology Description 100 MW

Fuel Type Wind



13%


Labour Costs 15%

Construction profile % of capital Cost Year 1 : 80%

Year 2: 20%

First year available for Construction Available for construction in 2012. Estimate for a project to achieve commercial operation based on a 2012 start is 2015 – based on a 3 year allowance for permitting, finance, engineering, procurement and construction

Typical new entrant size Can be any size and can be built on over time. Basis is for a nominal 100 MW plant.

Economic Life While the design life of most wind generation equipment is 20 years, there are few examples of generation equipment being operated for the duration

0

10

20

30

40

50

60

0 5 10 15 20 25

FOM

($/M

W/y

ear)

Thou

sand

s

Operating Year

100MW Wind Farm: FOM ($/MWAC/Year)



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Technology Description 100 MW of their design life.

Once a project is established it is anticipated that at some stage during the design life period, the project will be repowered with more efficient machines. Wind projects are thus anticipated to have an operational life in excess of the design life of the equipment

Lead time for development (years) Development time for a typical wind farm project is in the order of 4 to 7 years from site identification to operation.

Minimum stable generation level (% capacity)

1% – 2% (Depending on configuration of machine)

Thermal Efficiency (sent out – HHV) Not Applicable


Not Applicable

Auxiliary Load (%) Approximately 0.5% (depending on machine configuration). Auxiliary loads for a wind farm are generally low, and are incorporated into the electrical losses within the facility. The net capacity factor thus accounts for the auxiliary load

Capacity Factor 38%

FOM ($/MW/year) for 2012 Refer Graph Above – average $40,000/MW/year


VOM ($/MWh sent out) 2012 Refer Graph Above – average $12/MWh





+ / - 30%

WorleyParsons has examined the capital costs associated with wind energy projects in respect of five different future stationary energy sector scenarios. The examination considered a 100 MW on shore wind energy project.

This examination used a range of techniques to arrive at forward price curves for each sector scenario through to 2032.



63

The techniques used included benchmarking against recent project costs known to WorleyParsons and comparison with forward estimates from various industry sources, including the International Energy Agency and wind energy industry bodies such as the Global Wind Energy Council.

In addition to the wind energy specific factors considered, the new entrant costs were escalated according to the estimated category cost split and scenario-specific parameters of exchange rate trend, productivity trend and commodity price trend, as per all other power generation technology curves generated by WorleyParsons under this study.

5.8 Geothermal


The world's first commercial geothermal power plant was built at Larderello, Italy, in 1911. In 1958, New Zealand became the second major industrial producer of geothermal electricity when its Wairakei station was commissioned. After some time to bed in and subsequent expansion, Wairakei has consistently produced over 160MW at availabilities of around 95%. This was the first plant to use flash steam technology. In 1960, Pacific Gas and Electric began operation of the first successful geothermal electric power plant in the United States at The Geysers in California. These early steam turbine based plants provided the foundation for development of dry steam and flash based geothermal industry.

The steam-flash cycle technology is not well suited to smaller plants operating at lower reservoir fluid temperatures. This lead to the development of binary cycle power plant, which was first demonstrated in 1967 in Russia and later introduced to the USA in 1981. This technology allows the economic use of much lower temperature resources than were previously achievable. Early binary plants were generally complicated and sought to use techniques to improve the cycle efficiency, which resulted in poor availability. After a short while, one supplier simplified the binary plant design and supplied smaller modular units – Ormat went on to capture over 90% of the geothermal binary plant market. The market for binary plant is now expanding and new entrants are responding to meet the increased demand.

Currently 11% of worldwide installed geothermal generation capacity is based on binary cycle technology. When analysed by the number of units installed the number of binary plants are dominant with a 44% share of geothermal plants by type. In the context of the Australian geothermal plays, it is likely that binary plant will play a dominant role due to its better efficiency at lower temperatures and capital cost advantage for smaller plant size.

Binary plant is dominated by Organic Rankin Cycle (ORC) technology. A simplified schematic is shown in Figure 9 below. The Organic Rankine Cycle is a thermodynamic process, where heat is transferred from the geothermal brine to a working fluid at a constant pressure. The working fluid is a hydrocarbon or a refrigerant, which has a boiling point lower than water and makes the cycle suitable for energy conversion at lower temperatures. The working fluid is vaporized and then expanded in a vapour turbine that drives a generator, producing electricity. The vapour is then condensed to liquid and pumped back to the heat exchangers to complete a closed cycle.

http://en.wikipedia.org/wiki/Larderello

http://en.wikipedia.org/wiki/Wairakei_Power_Station

http://en.wikipedia.org/wiki/Pacific_Gas_and_Electric



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Figure 9 : Diagrammatic Representation of Simplified ORC Plant (WorleyParsons)

5.8.2 Australian Experience

There are two geothermal plays in the Australian geothermal environment, namely Hot Sedimentary Aquifer (HSA) and Engineered Geothermal System (EGS).

A Hot Sedimentary Aquifer (HSA) system is a characterised by hydrothermal groundwater resources in a sedimentary basin. This setting is typical of some of the low temperature resources in the USA, particularly Nevada, which were developed in the eighties. There are two characteristics required for successful production wells in HSA play. The aquifer must have sufficient temperature to be economically viable and sufficient permeability to provide an economic flow rate. Data available from shallower oil wells has been used to predict temperatures with reasonable accuracy, but no established methods exist for accurate prediction of permeability. This means that it is necessary to drill expensive exploration wells to determine if there is sufficient permeability for a viable project.

The current understanding of EGS dates back to the first efforts to extract the earth’s heat from rocks with no pre-existing high permeability at the Fenton Hill hot dry rock experiments in the early 1970’s. Building on the experience from the Fenton Hill project, the Rosemanowes, Hijiori, Ogachi, and Soultz projects attempted to develop further the concept of creating a reservoir in crystalline rock in other geological settings.

The recent development of EGS has been most successful in Europe, where feed-in-tariffs have provided the required stimulus for commercialisation. The 3MW plant at Landau is the first



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commercially funded EDS project and others are planned in Switzerland, Spain, UK and several other European countries.

Geodynamic’s development at Habanero has a pilot plant using a steam turbine and is best viewed as a binary system since the steam is confined to a closed circuit with the high pressure geothermal fluid transferring heat to this cycle through a set of heat exchangers. This is fundamentally different to the more common hydro-thermal steam turbine generation plant, where steam is separated from geothermal fluid, then passed through the turbine.

Development of a geothermal project requires the consideration and evaluation of a number of factors, such as site (geography), geology, reservoir characteristics, geothermal temperature, plant size and type. In 2009, New Energy Finance published a breakdown of estimated costs for a typical 50MW hydro-thermal power plant, which is shown in a simplified form in Figure 10, together with estimates for HSA and EGS projects of a similar size.

The majority of the overall cost moves from being focused on power plant construction to well drilling progressively with the change from hydro-thermal to HSA and finally to EGS. The power plant

Figure 10: Estimated Developmental Cost Breakdown for a 50MW Geothermal Power Plant (Source New

Energy Finance 2009)



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construction costs have typically been subject to wide variation based on differing technologies reflecting a wide range of geothermal resource characteristics. It can be expected that HSA and EGS power plant technology will not be subject of such large scatter since the geothermal fluid will probably always be hot brine between 120 and 250°C. This will put EGS power plant costs at the high end of the range for existing geothermal plants and HSA at the extreme high end. Lower reservoir temperatures and higher ambient temperatures, both reduce the cycle efficiency and adversely affect the project economics. The high reservoir pressures associated with EGS require more costly heat exchangers, than normally used.

There are two main factors affecting the well costs:

• The costs of the wells themselves, including remedial works and lost wells; • The average productivity of the wells, including wells which may not become useful producers or

injectors. Multiple fractures in EGS wells and stimulation of HSA are unproven in the Australian developments to date.

The development of a geothermal power plant has an unusual risk profile. It is normal to validate the “fuel supply” by drilling between 30 -50% of the required production wells before committing to the power plant construction. In a well-managed reservoir, with the appropriate extraction rates, maintaining the fuel supply is limited to the occasional make-up well. This means that the fuel supply, once secured, is effectively isolated from any market changes; however, the up-front investment in well drilling is analogous to stockpiling about ten years fuel.

Geothermal generation is also unique amongst the renewables in that it provides base load power and is not influenced by climatic conditions such as wind and hydro.

There is difficulty in predicting the well completion cost as there is significant variance in well completion costs for both oil & gas and geothermal well drilling. In addition to this uncertainty, the production rate of the wells is not well defined. For HSA in Australia, there is only a limited database to draw on with only two known wells having been drilled to target depth. Multiple fractures are planned for EGS, but this has not been demonstrated yet.

Capital cost estimates for both HSA and EGS plays are highly dependent on site and resource characteristics as well as the drilling costs. Even without the uncertainty of future cost forecasting, large cost uncertainty margins must be applied to these cost estimates, and to the cost breakdowns hereunder.

Exploration costs must be borne by a project years (possibly many years) in advance of the completion of a project and the dispatch of the first MWh to the power market. The share of the long run cost of power that exploration costs therefore represent are highly sensitive to the cost of capital applicable to the project – itself a number which may vary over time as investor sentiment and uncertainty over a particular resource development changes.

Technology Description HSA EGS

Fuel Type Geothermal Geothermal



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Capital Costs A$/kW net

Drilling (all wells)

Power Plant

Brine Reticulation

Geoscience & Permitting

7,000 $/kW

53%

36%

6%

6%

10,600 $/kW

75%

19%

3%

3%


43% 46%

International Equipment 23% 17%

Labour Costs 34% 37%

Construction profile % of capital Cost

Year 1 40%

Year 2 40%

Year 3 20%

Year 1 40%

Year 2 45%

Year 3 15%

First year available for Construction 2020 2025

Typical new entrant size 10-20MW 5-10MW

Economic Life 25-50 years 25-50 years

Lead time for development (years) 3 years 5 years

Minimum stable generation level (% capacity)

Not applicable Not applicable

Thermal Efficiency (sent out – HHV)

Resource dependent Resource dependent


Resource dependent Resource dependent

Auxiliary Load (%) 7-13% depending on reservoir 6-12% depending on reservoir

Capacity Factor 85 – 90% 85 – 90%

FOM ($/MW/year) for 2012 200,000 170,000

FOM Escalation Rate (% of CPI) Refer section 3.9 Refer section 3.9

VOM ($/MWh sent out) 2012 0 0

VOM Escalation Rate (% of CPI) Refer section 3.9 Refer section 3.9



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Percentage of emissions captured (%)

Not applicable Not applicable

Emissions rate per kgCO2e/MWh 0 0


+60 / -40% +60 / -40%

5.8.3 Expected Technological Improvement

Cost and technical risk are major obstacles to future development of such deep and expensive (due to the lower efficiency of binary cycles in both HSA and EGS) resources, with recent and future advances in fracturing technology offering the potential for step change reductions in per-well (and therefore due to the major capital cost of wells per-dollar) energy costs. Fracturing technologies stand to benefit from the major R&D expenditures in development of vast US and Canadian (and other worldwide) shale gas resources.

Hydrothermal technologies are generally considered proven and commercial technologies. Power generation equipment is readily available for hydrothermal plants in various capacities and the drilling technology required for tapping the resource is now well established with lower risk than in the past.

However, risks do still exist with hydrothermal power plants and exploration and drilling costs can be expensive in some circumstances. Occasionally drilling results in dry holes and there is also risk associated with reservoir cooling. In the past two decades, no real improvements have been made in the exploration process25. Risk also lies in reservoir management to maintain the reservoir output. Reservoir life depends on the success of re-injection into the geothermal reservoir, and supplemental injection may be needed to extend the reservoir life.

Hot Rock (HR) is not yet a commercial technology, though it is believed to be proven as technically feasible, with technology readiness projected for 2015. Like hydrothermal plants, HR is a base load renewable technology that is low cost to operate and has low cost volatility due to a lack of fuel costs. The same plant and drilling technologies can be used as hydrothermal plants, but with a less site-specific restriction on plant location compared to a hydrothermal resource. The resource risk is also lower than that for a hydrothermal plant.

HR has a high upfront cost, up to 70-80% of total costs, in developing the well field. Resource exploration and assessment methods need to be improved to reduce costs and stimulation technologies for generating the cracks within the rock also need improved development.

HSA is also not yet commercially proven. However, it is often considered the easier to develop of the near term geothermal projects. HSA uses a conventional dual fluid cycle, involves shallower drilling,

25 Australian Electricity Generation Technology Costs – Reference Case 2010, February 2010, Prepared by EPRI/WorleyParsons



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and does not require resource stimulation, and therefore it is considered less risky than HR. Several potential sedimentary basins have been identified in Australia, which may further reduce exploration, drilling, and reservoir risks.

The key to HSA research and development is to find shallow systems that reduce the development costs and allow the use of proven hydrothermal systems and supporting technology. Secondary reservoir stimulation techniques, known as Secondary Enhancement of Sedimentary Aquifer Play (SESAP) is also being researched as a way to increase permeability and production rates of HSA.

Australia does not have the wet, high-temperature geothermal environments found in volcanically active countries such as in New Zealand. Consequently, Australia’s hydrothermal systems are neither hot enough nor under enough pressure to produce large amounts of steam. Therefore most Australian geothermal resources will be exploited using dual fluid cycle power generation systems and HR resources.

Hot rock is still largely experimental as it has yet to be developed commercially. Well costs increase exponentially with depth and because HR resources are much deeper than hydrothermal resources, they are much more expensive to develop. Regardless of the fact that the technical feasibility of creating HR reservoirs has been demonstrated at experimental sites in other parts of the World operational uncertainties regarding the resistance of the reservoir to flow, thermal drawdown over time, and water loss have so far made commercial development very risky. Lower-cost resource assessment and lower cost drilling technologies are required to take HR systems to the level of commercial use.

It is understood that characterising the commercial potential of identified geothermal reservoirs very early in the project phase is a high priority. Techniques such as fracture mapping, more accurate thermal-gradient wells, and other, untested methods should be evaluated and refined, if appropriate. The main objective will be to measure the temperature, fluid characteristics, and permeability of the resource prior to committing to expensive production wells and generation equipment.

Since HR systems are still widely experimental, evaluation and testing must be conducted to confirm the economic viability of these systems.

Because Australia’s geothermal resources do not appear to support the more commercial hydrothermal technologies, advancement of geothermal power outside of HSA in Australia will depend upon the development of rock fracturing technologies to allow for high production rates from the abundant HR resource.

Most of the necessary drilling and well testing equipment is adapted from the oil and gas industry which presents a major issue for geothermal projects competing with the higher rewarding oil & gas projects. Another major issue for geothermal projects in Australia is that the most active areas for geothermal opportunities are in very remote locations away from the main load centres. This implies that geothermal projects will most likely be developed for local power supply since long distance HV transmission lines would probably be prohibitive.



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5.8.4 Resource Replenishment

Hydrothermal systems often require make up wells to maintain production as the reservoir pressure is drawn down due to extraction of fluid. Reinjection is used to mitigate this, but it is difficult to introduce “cold” fluid into the reservoir without affecting the production temperature. Steam flash plant uses cooling towers, which means that some of the fluid extracted is lost to evaporation, even with reinjection.

Binary plant often uses air cooled condensers, which enables all of the fluid to be reinjected. This is what is expected for EGS & HSA and will probably mean that make up well drilling will not be required as for hydrothermal systems. A more likely scenario is that the production temperature will decline. Therefore no make-up well drilling is included in the cost estimate.

5.9 Integrated Solar Combined Cycle (ISCC)

A cost estimate of A2155 $/kW was used as the starting point for a 502 MW (net) ISCC plant. The capital cost was estimated from a plant modeled on a single Alstom GT26 gas turbine with a three pressure reheat HRSG and a solar field being nominally sized for a solar field multiple of 1.2 with no thermal storage.

The table below includes key data from the GT Pro model used to size the ISCC plant:

CCGT – no solar CCGT - solar

Plant Output (gross) MWe 423.4 515.7

Plant Output (net) MWe 408.3 502

Auxiliary MWe 15.1 23.7

% 3.6 4.5

Fuel CH4 CH4

CO2 Intensity (net) kgCO2/MWhr 340 276

Plant net eff (HHV) % 50.5 62.1

Solar field heat to steam

MWth n/a 340.3

Solar field price $ n/a $617,574,000

CC Plant Price $ $419,019,388 $464,129,592

Total Plant Price $ $419,019,388 $1,081,703,592



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Technology Description Integrated Solar Combined Cycle

Fuel Type Natural Gas



18%


Labour Costs 26%

Construction profile % of capital cost Year 1: 60%

Year 2: 40%








Auxiliary Load (%) .5%

FOM ($/MW/year) for 2012 10,000


VOM ($/MWh sent out) 2012



Emissions rate per kg GGCO2e/MWh or GGCO2e/GJ fuel

276kg CO2e/MWh


+/- 40%

5.10 Cost Curves

Cost curves for each technology case were produced and are contained in Appendix 1.

The curves are based on net of sent out power.


h:\jobs oracle\101010-00676 - aemo new tech constn cost\02_reports\aemo report rev 2.docx 101010-00676 : Report : 10 February 2012

Appendix 1: Technology and Cost Curves



Appendix 2 Battery Limits



Item Coal Gas Renewable Energy

Fuel Inlet end of the coal stockpile and reclaim system at the coal yard

Gas supply pipeline to power plant boundary

Cooling Water Power plant boundary. Power plant boundary. Power plant boundary (where applicable).

Site Drains Power plant boundary Power plant boundary. Power plant boundary.

Outgoing Power Switch-yard outgoing dead-end tower

Switch-yard outgoing dead-end tower

Switch-yard outgoing dead-end tower

Roads Plant service roads should terminate at the site access gate.

Plant service roads should terminate at the site access gate.

Plant service roads should terminate at the site access gate.

CO2 Outlet flange of the compressor plant

Outlet flange of the compressor plant (where applicable)



Appendix 3 - Types of Generation Plant in AEMO Regions



NQ CQ SEQ SWQ NNS NCEN CAN SWNSW NVIC CVIC MEL LV TAS SESA ADE NSAIGCC plant with CCS based on brown coal

X

IGCC plant with CCS based on bituminous coalX X X X X

Pulverized coal supercritical plant with CCS based on brown coal X

Pulverized coal supercritical with CCS based on bituminous coal X X X X X

Oxy-combustion pulverized coal supercritical with CCS based on bituminous coal X X X X X

CCGT plant based on natural gasX X X X X X X X X X X X X X X X

CCGT with CCS based on natural gasX X X X X X X

Solar thermal, compact linear Fresnel reflector technology without storage X X X X X X X X X X X X X

Solar thermal, parabolic trough technology with 6 hours storage X X X X X X X X X X X X X

Solar thermal, central receiver technology with 6 hours storage X X X X X X X X X X X X X

Solar PV, non-trackingX X X X X X X X X X X X X

On shore wind turbine, 100 MW wind farmX X X X X X X X X X X X X

Geothermal, HAS (hot sedimentary aquifers)X X X X X X X

Geothermal, EGS (enhanced geothermal system)X X X X X X X

Integrated solar combined cycle (ISCS); parabolic trough with combined cycle gas (solar component) X X X X X X X X X X X

Potential Types of Generation Plant in Various AEMO Regions



Appendix 4 - Plant Schematics



4.1 –IGCC plant with CCS based on brown coal



4.2–IGCC plant with CCS based on bituminous coal



4.3–Pulverized Coal Supercritical Brown Coal with CCS



4.4–Pulverised Coal Supercritical Bituminous Coal with CCS



4.5–CCGT Based on Natural Gas



4.6–CCGT with CCS Based on Natural Gas



Appendix 5 Regional Capital Cost Modifiers



Appendix 6 – References

Acronyms

Table of Figures



ACRONYMS AEMO Australian Energy Market Operator ASU Air Separation Unit CCGT Combined Cycle Gas Turbine CCS Carbon Capture and Storage CPI Consumer Price Index EGS Enhanced Geothermal System EPC Engineer, Procurement, Construction FOM Fixed Operational and Maintenance GDP Gross Domestic Product GJ Gigajoule HSA Hot Sedimentary Aquifers HHV Higher Heating Value HRSG Heat Recovery Steam Generator IGCC Integrated Gas Combined Cycle ISCS Integrated solar combined cycle LRET Large Scale Renewable Energy Target MRET Mandatory Renewable Energy Target MEA MonoEthanolAmine MWAC Megawatt (AC) MPa MegaPascal MWh Megawatt hours NEM National Electricity Market NTNDP National Transmission Network Development Plan OEM Original Equipment Manufacturer OCGT Open Cycle Gas Turbine PC Pulverised Coal SESAP Secondary Enhancement of Sedimentary Aquifer Play SWG Stakeholder Reference Group VOM Variable Operational and Maintenance



TABLE OF FIGURES

Figure 1 : Exchange Rate Variation as Applied .................................................................................... 17

Figure 2: Impact for Technological Improvement .................................................................................. 19

Figure 3: Anticipated Cost of Renewable Technology Development .................................................... 20

Figure 4 Improvement in Heat Rate with Increasing Steam Conditions ............................................... 33

Figure 5 : Capital Cost Breakdown ....................................................................................................... 48

Figure 6 : Basis for Capital Cost Split ................................................................................................... 56

Figure 7 : Wind Farm VOM ($/MWh) .................................................................................................... 60

Figure 8 : Wind Farm FOM ($/MW AC/year) ........................................................................................ 61

Figure 9 : Diagrammatic Representation of Simplified ORC Plant ....................................................... 64

Figure 10 : Estimated Developmental Cost Breakdown for a 50MW Geothermal Power Plant ........... 65

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