Australian Energy Technology
Assessment 2013 Model Update
December 2013
1
Arif Syed (BREE) 2013, The Australian Energy Assessment (AETA) 2013 Model update, Canberra,
December 2013.
© Commonwealth of Australia 2013
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ISBN 978-1-925092-14-1 (online)
This report was produced by Arif Syed, Modelling and Policy Integration Program, BREE. It is based on
analysis undertaken by WorleyParsons, commissioned by the Department of Industry.
Acknow ledgements
The Project Steering Committee comprised Professor Quentin Grafton, Bruce Wilson, Wayne Calder, and Dr
Arif Syed of BREE; Rick Belt, and Mark Stevens of the Department of Industry; Damir Ivkovic, of ARENA,
Professor Ken Baldwin of the Australian National University, Dr Alex Wonhas of the Commonwealth
Scientific and Industrial Research Organisation, and Nathan White of the Australian Energy Market Operator.
The guidance and assistance of the AETA Steering Committee members, and AETA Stakeholders Group are
gratefully acknowledged. Davin Nowakowski, and Shamim Ahmad of BREE provided valuable support to the
preparation of this report.
Postal address:
Bureau of Resources and Energy Economics
GPO Box 1564
Canberra ACT 2601 Australia
Phone: +61 2 6243 7000
Email: info@bree.gov.au or Arif.Syed@bree.gov.au
Web: www.bree.gov.au
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FOREWORD
The inaugural Australian Energy Technology Assessment (AETA) 2012 report released in
mid-2012, was an important step forward in improving the quality and transparency of
information available for market-ready and prospective electricity generation technologies in
Australia. The AETA 2012 provided many important insights particularly the relatively
rapid cost reductions expected for a range of renewable energy technologies over the course
of the next decade.
To ensure that technology costs remain up to date, this AETA 2013 Model Update report
provides electricity generation technology cost parameters as an update to the values
presented in AETA 2012. All of the 40 technologies considered in AETA 2012 are included
in this update, and encompass a diverse range of energy generation sources including
renewable energy (such as wind, solar, geothermal, biomass and wave power), fossil fuels
(such as coal and gas), and nuclear power.
The AETA 2013 Model Update takes into account new information on technology generation
costs and has been the subject of wide consultation with relevant industry stakeholders and a
stakeholder reference group drawn from industry and research/academic organisations with
interests and expertise in a diverse range of electricity generation technologies.
As is the case for all such assessments, the cost estimates in this report reflect assumptions
made on a mix of critical technical and economic parameters. Importantly the LCOE
estimates do not include site specific or systems costs. The AETA 2013 Model Update
results also do not include carbon or other environmental costs that may be associated with
various technologies. Clearly the extent to which these might apply in the market or
through regulation, may impact on generation or delivered costs of electricity.
Importantly the transparency and detail provided in the AETA model enables users to apply
their particular assumptions to construct their own LCOE based on Australian conditions
and a copy of the model is available upon request. It is essential to energy planners, energy
modellers and, indeed, anyone interested in exploring different scenarios and energy
futures.
Bruce Wilson
Executive Director
Bureau of Resources and Energy Economics
3
CONTENTS
About the Bureau of resources and energy economics
2
Acknowledgements ....................................................................................................................... 2
FOREWORD ...................................................................................................................................... 3
ACRONYMS/ABBREVIATIONS ........................................................................................................ 8
GLOSSARY ........................................................................................................................................ 9
EXECUTIVE SUMMARY ............................................................................................................10
1
INTRODUCTION ..............................................................................................................12
1.1
Background to the AETA 2012 report ...............................................................................12
1.2
Methods and Assumptions of the AETA 2012 Report and Model ....................................12
1.3
2
1.2.1
Macro assumptions ..............................................................................................12
1.2.2
Technical assumptions ........................................................................................13
1.2.3
Levelised cost of energy (LCOE) .........................................................................13
Methodology of the AETA 2013 Model Update ................................................................13
1.3.1
Caveats on the use of LCOE ...............................................................................14
1.3.2
Organisation of the report ....................................................................................14
AETA MODEL PARAMETER CHANGES ........................................................................16
2.1
2.2
3
Stakeholder Initiated Changes ..........................................................................................16
2.1.1
Nuclear Capital Costs ..........................................................................................16
2.1.2
Carbon Capture and Storage (CCS) Retrofit Thermal Efficiency ........................17
2.1.3
Amortisation period ..............................................................................................19
No Carbon Pricing.............................................................................................................19
CONSIDERATION OF OTHER ISSUES ..........................................................................20
3.1
Representation of Uncertainty ..........................................................................................20
3.2
Application of Learning Curves .........................................................................................20
3.3
General Costs Considerations ..........................................................................................21
3.4
3.3.1
Fuel Costs ............................................................................................................21
3.3.2
CCS Costs ...........................................................................................................21
3.3.3
Opportunity Costs ................................................................................................22
Capital and Construction Costs ........................................................................................22
4
3.5
Costs Associated with Solar Technologies .......................................................................23
3.6
Costs Associated with Nuclear Technologies ...................................................................24
3.7
Further Technologies ........................................................................................................24
3.8
Auxiliary Loads ..................................................................................................................24
4
WIND, PV AND CSP OPERATIONS AND MAINTENANCE (O&M) COST UPDATE .....25
4.1
Operation and Maintenance Costs ...................................................................................25
4.2
Operating and Maintenance (O&M) Changes in summary ..............................................26
4.3
Wind ..................................................................................................................................28
4.4
4.3.1
Introduction ..........................................................................................................28
4.3.2
Review of Evidence .............................................................................................29
4.3.3
Updated O&M Figures for Australia .....................................................................33
Solar Photovoltaics (PV) ...................................................................................................36
4.4.1 Introduction ................................................................................................................36
4.5
4.6
4.7
5
4.4.2
Review of the Evidence .......................................................................................37
4.4.3
AETA 2012 O&M PV costs report comparison ....................................................37
AETA 2013 PV O&M Costs Update..................................................................................40
4.5.1
O&M Learning Rates ...........................................................................................41
4.5.2
Conclusions - PV..................................................................................................42
Concentrating Solar Power (CSP) ....................................................................................43
4.6.1
Introduction ..........................................................................................................43
4.6.2
Review of the evidence ........................................................................................43
4.6.3
AETA 2012 O&M CSP costs report comparison .................................................44
AETA 2013 O&M Learning Rate recommendation ...........................................................53
CHANGES TO THE LCOE ...............................................................................................55
5.1
Conclusions ......................................................................................................................63
REFERENCES .................................................................................................................................64
Appendix A: Electricity Generation Technologies in AETA 2012 Report and Model
67
Appendix B: Consultations with Stakeholders
69
BREE CONTACTS ..........................................................................................................................71
5
INDEX OF TABLES
Table 1: Model Changes, Nuclear Technologies .............................................................................17
Table 2: Model Changes, CCS Retrofit Thermal Technologies ......................................................18
Table 3: Model Changes, amortisation period .................................................................................19
Table 4: Model Changes, O&M costs ................................................................................................27
Table 5 : Wind O&M costs used in the AETA 2012 report ...............................................................29
Table 6 : Comparison of AETA 2012 wind O&M estimates with new references for 2013 ..........35
Table 7 : Recommended AETA 2013 values .....................................................................................36
Table 8 : AETA 2012 reference plants technical characteristics and OPEX costs .......................39
Table 9 : Comparison of historical estimated PV and O&M costs in the public domain .............39
Table 10 : 2013 PV O&M costs compared to 2012 PV O&M costs .................................................40
Table 11 : 2013 updated O&M costs compared to new referenced O&M costs (7-2) ...................41
Table 12 : AETA 2012 Reference Plant Technical Characteristics .................................................45
Table 13 : AETA 2012 O&M Opex costs on a per kWh basis ..........................................................46
Table 14 : PT and ST Reference Plant Characteristics....................................................................47
Table 15 : 2013 CSP O&M Costs Compared to 2012 O&M Costs ...................................................48
Table 16 : Estimated LCOE form Existing and Hypothetical Trough and Solar Tower CSP
Technologies .......................................................................................................................................51
Table 17 : AETA Learning Rate Comparison ....................................................................................54
6
TABLE OF FIGURES
Figure 1 - Effect of country variables on LCOE of wind plant ........................................................31
Figure 2 - Typical cost increasing trends in wind farm O&M costs with commercial
operations date....................................................................................................................................32
Figure 3 - Trends in offshore wind farms and estimated impact on LCOE ...................................33
Figure 4 - O&M Costs (per MW) and Technician Numbers (per 100MW) for total wind
turbine O&M (Opex) ............................................................................................................................34
Figure 5 - AETA 2012 FOM and VOM Percentages of Total OPEX Costs ......................................46
Figure 6 - Comparison of OPEX Costs per Total Annual Plant Production per Year:
AETA 2012 Report and 2013 Update .................................................................................................49
Figure 7 - Expected LCOE Reductions for CSP Technology from 2012 to 2025 ..........................52
Figure 8: Updated LCOEs for AETA 2013 Model technologies, values for 2012 (NSW), with
carbon price set to zero.
56
Figure 9: Updated LCOEs for AETA 2013 Model technologies, values for 2020 (NSW), with
carbon price set to zero. .....................................................................................................................57
Figure 10: Updated LCOEs for AETA 2013 Model technologies, values for 2025 (NSW), with
carbon price set to zero. .....................................................................................................................58
Figure 11: Updated LCOEs for AETA 2013 Model technologies, values for 2030 (NSW), with
carbon price set to zero. .....................................................................................................................59
Figure 12: Updated LCOEs for AETA 2013 Model technologies, values for 2040 (NSW), with
carbon price set to zero. .....................................................................................................................60
Figure 13: Updated LCOEs for AETA 2013 Model technologies, values for 2050 (NSW), with
carbon price set to zero ......................................................................................................................61
Figure 14: Comparison of AETA 2013 Model Update and AETA 2012 LCOE estimates,
selected technologies .........................................................................................................................62
7
ACRONYMS/ ABBREVI ATIONS
AETA
BREE
CAPEX
CSP
DAT
EPIA
EPRI
ESTELA
FOM
FT
h
IDEA
IEA
IRENA
kW
kWh
LCOE
LF
m2
MENA
MW
MWh
MWe
NREL
O&M
OEM
OPEX
PT
PV
R&D
SAT
SEGS
SEIA
SEPA
ST
TES
USD
VOM
WB
Australian Energy Technology Assessment
Bureau of Resources and Energy Economics
Total capital expenditures
Concentrating Solar Power Technologies
Dual axis tracking
European Photovoltaic Industry Association
Electric Power Research Institute
European Solar Thermal Electricity Association
Fixed operation and maintenance costs
Fixed Tilt
Hours
Institute for Energy Diversification and Saving
International Energy Agency
International Renewable Energy Agency
Kilowatts
Kilowatt hours
Levelised Cost of Energy
Lineal Fresnel Reflector CSP Technology
Square Meters
Middle East and North Africa region
Megawatts
Megawatt hours
Megawatt hours electric
National Renewable Energy Laboratory
Operation and maintenance
Original Equipment Manufacturer
Total operating expenditures
Parabolic Trough CSP Technology
Photovoltaic
Research and Development
Single axis tracking
Solar Electricity Generating System
Solar Energy Industries Association
Solar Electric Power Association
Solar Tower CSP Technology
Thermal Energy Storage System
United States Dollar
Variable operation and maintenance costs
The World Bank organization
8
GLOSS ARY
Amortisation Period: the period over which a plant must achieve its economic return.
Auxiliary Load: the internal or parasitic load from the electricity required to sustain the
operation of a plant.
Capacity Factor: the ratio of the actual output of a power plant over a period of time and its
potential output if it had operated at full nameplate capacity the entire time.
Capital Cost: the cost of delivery of a plant, not including the cost of finance.
Discount Rate: the rate at which future values are discounted or converted to a present
value.
First-of-a-Kind Plant cost: costs necessary to put a first commercial plant in place and that
will not be incurred for subsequent plants. Design and certification costs are examples of
such costs.
First Year Available for Construction: the year in which the technology will be available
for commercial deployment globally.
Gross Capacity: maximum or rated generation from a power plant without losses and
auxiliary loads taken into account.
International Equipment Cost: the cost for internationally sourced equipment associated
with the project.
Labour Cost: the component of the delivery cost for a plant associated with local
(Australian) labour.
Lead time for Development: the time taken from inception to financial close. This includes
permitting, approvals, and engineering design.
Levelised Cost of Energy: the minimum cost of energy at which a generator must sell the
produced electricity in order to achieve its desired economic return.
Local Equipment Cost: the cost of locally sourced (Australia) plant and equipment for the
project.
Net Capacity: the export capacity of a generation plant – i.e. the Gross Capacity less the
losses and auxiliary loads of the plant.
Nth-of-a-kind plant cost: all engineering, equipment, construction, testing, tooling, project
management, and other costs that are repetitive in nature and would be incurred if a plant
identical to a FOAK plant were built. The NOAK plant is the nth-of-a-kind or equilibrium
commercial plant of identical design to the FOAK plant.
Sequestration: the process of transport and storage of Carbon Dioxide (CO 2).
Thermal Efficiency: the ratio between the useful energy output of a generator and inputs.
9
EXECUTIVE SUMMARY
This Report provides electricity generation technology cost parameters as an update to those
presented in the Australian Energy Technology Assessment (AETA) Report and Model
published in July 2012. This update takes into account a range of new material reported in the
public and private domain, further discussions with asset owners and technology developers,
and input from key experts in relation to these costs.
The AETA 2012 Model estimated levelised costs of energy (LCOE) for a set of 40 market
ready and prospective electricity generation technologies. LCOE can be interpreted as the
long-run marginal cost of electricity generation. These were estimated by breaking down
the cost drivers for a technology into its key constituent parts such as capital cost, fixed and
variable ‘operations and maintenance’ (O&M) costs, and where applicable, fuel costs, and
CO2 storage costs. While the LCOEs included carbon costs, project specific, regulatory or
system based costs were not included although clearly these may have a significant impact
on the delivered price of electricity.
The AETA 2013 Model update generally follows the same approach although comparable
LCOE results are presented without carbon costs, reflecting the Government’s intention to
repeal carbon pricing. To the extent that alternative emissions reduction measures impact on
the electricity generation sector this may have different implications for fossil fuel and/or
renewable based technologies.
For these reasons some caution should be applied when interpreting LCOE estimates. These
estimates best illustrate potential and relative “off-the-shelf” cost competitiveness rather than
a firm predictor of market outcomes or the commercial viability of individual projects.
The key features of the LCOE cost parameters in the AETA 2013 Model update with respect
to the AETA 2012 Model can be summarised as follows:
 renewable technologies have generally higher LCOEs than the lowest cost nonrenewable technologies, and the relative LCOE rankings significantly change post
2030. The LCOE of solar PV becomes lower than the non-renewables, from mid2030 onwards;
 however, wind based generation is estimated to already have a lower LCOE than
many new build, comparable fossil-fuel generation technologies;
 LCOE costs vary substantially across the technologies from $89/MWh (combined
cycle gas turbine) to $351/MWh (solar thermal Linear Fresnel) in 2012, and
$73/MWh (PV non-tracking) to $247/MWh (IGCC black coal CCS) in 2050;
 changes are made to nuclear capital costs and nuclear technology plant’s ‘first year of
construction’, carbon capture and storage (CCS) retrofit thermal efficiency and
amortisation period for various technologies to include construction period;
 a reduction in onshore wind O&M costs of 18 per cent;
10
 a reduction in offshore wind fixed O&M costs, and a three-fold increase in offshore
wind variable O&M costs, resulting in an overall increase of 50 per cent total O&M
costs;
 fixed tilt PV configurations have not seen significant changes in O&M costs;
 single axis tracking and dual axis tracking PV configurations are approximately 20-30
per cent reduced based on a better understanding of the associated O&M costs;
 concentrating solar power (solar thermal) O&M cost reduced between 8 per cent and 27
per cent; and
 the O&M learning rate for offshore wind and all solar technologies are increased from
0.2 to 2.5 per cent;
The overall impact of parameter changes by technology is given in the AETA 2013 Model
and in this report. As in the AETA 2012, the 2013 Model update provides technology
LCOEs for the years 2012, 2020, 2025, 2030, 2040, and 2050.
11
1
INTRODUCTION
The Australian Energy Technology Assessment (AETA) 2012 report published in July 2012
by the Bureau of Resources and Energy Economics (BREE 2012) undertook costing of 40
electricity generation technologies. This report made a provision that due to the fast changing
technology cost environment, cost and performance parameters assessed in the AETA 2012
model may be updated every year. In addition, a full report and ‘bottom up’ study will be
undertaken biennially, with the next report to be released in 2014.
The next fully updated AETA report is scheduled for completion in 2014. To ensure that cost
estimates for electricity generation technologies are current, and take into consideration the latest
developments, parameter estimates for the 40 technologies will be updated , where appropriate,
every six months in a manner consistent with the methods outlined in this report and in consultation
with the stakeholder reference group (BREE 2012, p. 24).
The purpose of this AETA 2013 Model Update report is to present findings arising from a
review of specific technologies by BREE. This review was assisted by comments made by
the AETA Project Steering Committee (PSC) members and AETA Stakeholders Reference
Group (SRG). WorleyParsons was commissioned to review cost parameters for the
technologies considered in the AETA 2012 model. Given the fast changing nature of solar
and wind technology operating costs, especial emphasis was placed on reviewing O&M costs
for wind and solar technologies. Changes to the model for the 2013 update are discussed in
the following sections.
1.1 Background to the AETA 2012 report
BREE engaged WorleyParsons in 2011-12 to develop cost estimates for 40 electricity
generation technologies under Australian conditions for AETA 2012. The AETA cost
estimates were developed with the active collaboration of the Australian Energy Market
Operator (AEMO), which utilised the AETA cost estimates for its National Transmission
Network Development Plan (NTNDP). In addition, the Commonwealth Scientific and
Industrial Research Organisation (CSIRO) provided technical advice as part of the AETA
project steering committee. The AETA 2012 provided technology costs for the years 2012,
2020, 2025, 2030, 2040, and 2050. These technologies encompass a diverse range of
energy sources including renewable energy (such as wind, solar, geothermal, biomass and
wave power), fossil fuels (such as coal and gas), and nuclear power (Appendix A). Since its
publication in July 2012, more than 1,000 requests have been made from BREE for the
AETA 2012 cost estimates (model) by domestic and international sources.
1.2 Methods and Assumptions of the AETA 2012 Report and
Model
1.2.1 Macro assumptions
Key macroeconomic assumptions are consistent with those detailed by the Australian
Energy Market Operator in its National Transmission Network Development Plan and by
the Australian Treasury (see BREE 2012 for a full set of assumptions).
12
1.2.2 Technical assumpti ons





all technologies were costed on a consistent and transparent basis, with itemisation of
component costs;
capital costs included direct (e.g. engineering, procurement and construction) and
indirect (e.g. owners) costs, but exclude transmission and decommissioning costs;
future cost estimates included assumptions about the exchange rate, productivity
variation, commodity variation and technology improvements;
fuel cost estimates were based on ACIL Tasman projections; and
projected growth rates for future operating and maintenance costs were provided.
1.2.3 Levelised cost of energy (LCOE)
LCOE can be interpreted as the long-run marginal cost of electricity generation. Key
factors used to calculate LCOE by technology include: amortisation period, discount rate,
capacity factor, CO2 emissions factor, CO2 capture rate, emissions price, CO2 storage cost,
fuel cost, variable and fixed O&M cost, and the capital cost.
LCOE is a key comparative cost indicator across technologies that is expressed in real
Australian dollars per Megawatt hour of electricity generation ($/MWh). The LCOE is the
price at which electricity must be generated from a specific plant to break even, taking into
account the costs incurred over the life of the plant (capital cost, cost of capital/financing,
operations and maintenance costs, cost of fuel, emissions price if applicable and CO2
sequestration). While LCOE is an invaluable tool for comparing technology costs, power
generation companies and/or investors who wish to choose a technology to deploy would
also need to consider other criteria such as site-specific costs, technology performance
characteristics and experience with the technology prior to any final investment decision.
AETA cost estimates are developed to provide design basis and plant characteristics,
performance parameters, capital cost estimates, fuel cost estimates, O&M cost estimates,
and LCOE estimates.
Regional impacts on capital and operating costs have been incorporated in the analysis.
These regions include Victoria, New South Wales (including ACT), South Queensland
(incorporating the South East Queensland, and Central Queensland AEMO regions), North
Queensland (incorporating the North Queensland AEMO region), Northern Territory,
North WA (Pilbara region), South WA (the South West Interconnected System region),
South Australia, and Tasmania.
1.3 Methodology of the AETA 2013 Model Update
As part of the AETA 2013 Model Update, BREE invited submissions from the AETA
Steering Committee and the Stakeholder Reference Group to provide commentary and
recommendations on the AETA 2012 Report and Model. Eight written submissions were
received in this regard. Changes were only recommended where specific substantiated
changes were received. The AETA 2013 model has been updated in accordance with the
above consultations, and under the same macro economic and technical assumptions as in
AETA 2012. The AETA 2013 model is freely available on request from BREE
(info@bree.gov.au).
Within this context, this report provides updated costs based on:
13
 relevant Australian and international reports on generation technologies that have been
published since AETA 2012 or have been newly discovered;
 new public domain information;
 new information from private sources that could be obtained;
 in-house experience of WorleyParsons; and
 input on O&M costs and learning rates from a number of industry stakeholders.
This AETA 2013 Model Update report provides supporting explanations and references, and
justifies amendments to the cost parameters of technologies, especially the O&M costs for
wind and solar technologies that were covered in AETA 2012 model.
1.3.1 Caveats on the use of LCOE
LCOE provides a generalised cost estimate and does not account for site specific factors
that would be encountered when constructing an actual power plant. As a result, the costs
associated with integrating a particular technology in a specific location to a specific
electricity network are not considered.
Projected LCOE does not necessarily provide a reliable indicator of the relative market
value of generation technologies because of differences in the role of technologies in a
wholesale electricity market. For example, projected LCOE does not provide a direct
indicator of electricity demand or generation in isolation with other emissions abatement
policies. Similarly, many technologies involve integration costs in addition to the LCOE, to
be able to reliably supply to the system. The value of variable (or intermittent) power plants
(such as wind, and solar) will depend upon the extent to which such plants generate
electricity during peak periods and the impact these plants have on the reliability of the
electricity system. Unlike dispatchable power plants (such as coal, natural gas, biomass,
and hydroelectric) – which are reliant on some form of stored energy (e.g. fuels, water
storage, or battery storage) – wind and photovoltaic power plants do not, typically, include
energy storage. Dispatchable plants, such as coal or gas fired plants, may involve negative
externalities (environment, fuel disposal or insurance costs, etc.), which are not always
reflected in their LCOEs.
The AETA LCOEs are restricted to only utility-scale or large scale technologies.
Consequently, small-scale technologies (e.g. small roof-top photovoltaics, fuel cells, cogeneration, and trigeneration) that may be relevant to distributed generation were not
included in the AETA 2012 analysis. LCOE cost estimates associated with distributed
photovoltaics are likely to differ substantially from utility-scale photovoltaic systems as a
result of differences in component costs (e.g. capital costs, operating and maintenance
costs) and performance characteristics (e.g. capacity factor).
1.3.2 Organisation of the report
This report is organised in five sections. After a brief introduction and purpose of the report
in this section, section 2 discusses the changes made to the AETA 2013 Model parameters as
a result of the discussions with Stakeholders and Steering Committee members on the
individual issues and technologies. Section 3 presents the issues that were considered but did
not result in the AETA Model parameter changes. Section 4 presents in detail the O&M cost
14
changes for wind and solar technologies covered in AETA 2012. Updated LCOE graphs, as
well as a comparison of the resultant AETA 2013 Model and AETA 2012 Model LCOEs are
presented in section 5, which also presents concluding comments.
15
2
AETA MODEL P ARAMETER CH ANGES
2.1 Stakeholder Initiated Changes
Consultations for the AETA 2013 Model update identified the following issues for
consideration:
 nuclear technology capital costs and ‘first year available for construction’;
 CCS retrofit thermal efficiency;
 amortisation period for all technologies; and
 O&M costs.
The O&M issue is discussed in section 4, whereas, rest of the issues are discussed below.
2.1.1 Nuclear Capital Costs
The AETA 2012 report and model presents costs for first of a kind (FOAK) and Nth of a kind
(NOAK) nuclear technologies. There could have been some confusion from the original
wording of Section 3.10 of AETA 2012 report. It starts by discussing Gen III plants currently
sold (presumably NOAK), however further in the document Gen III plants are referred to as
FOAK. The AETA 2012 report states that the capital costs are based on nuclear power plants
in the US. The NOAK value is what is represented in Table 3.10.1 in the AETA 2012 report
and model.
Although there are cost adjusting factors used for other technologies studied in the AETA
2012 report, there is no adjustment of the US cost base for Australian labour costs and for
adjustment of Australian equipment costs. Submissions indicated that an adjustment to costs
should also be used for nuclear to ensure there is commonality in the comparison.
This suggestion was considered appropriate and adjustment to the costs for nuclear
technologies was made. Based on the factors to convert US rates to Australian rates used in
the fossil fuel technologies, i.e. the factors from the Thermoflow software, the new nuclear
capital costs were calculated. The multiplier from Thermoflow for labour costs is 2.05 and
the factor for equipment costs is 1.3, both US to Australia.
Additionally, it was submitted that the first year available for construction of nuclear
technologies be extended. In support of this the submission argued that nuclear technologies
are examples of generation technology where legislation, regulation and public policy
planning is highly region-dependent and must therefore precede deployment by several years.
This was considered an appropriate submission and therefore the first year available for
construction in the model has been changed from 2012 to 2020. These changes are shown in
Table 1.
16
Table 1: Model Changes, Nuclear Technologies
AETA 2012 report reference
AETA 2012 model value
AETA 2013 update
Technology 37 Nuclear (GW Scale LWR)
Change first year available for Construction
2012
2020
4,210
6,392
3,470
5,268
7,908
11,778
4,778
7,116
Technology 37 Nuclear (GW Scale LWR)
Convert FOAK Capital Cost to Australian productivity
and commodity costs
Technology 37 Nuclear (GW Scale LWR)
Convert NOAK Capital Cost to Australian productivity
and commodity costs
Technology 38 Nuclear (SMR)
Convert FOAK Capital Cost to Australian productivity
and commodity costs
Technology 38 Nuclear (SMR)
Convert NOAK Capital Cost to Australian productivity
and commodity costs
The overall impact of these parameters on individual technology LCOE changes is given in
the AETA 2013 Model and in Section 5.
2.1.2 Carbon Capture and Storage (CCS) Retrofit Thermal Efficiency
Subcritical coal technologies with CCS retrofit were reported to have only slightly lower
thermal efficiency values compared with new build supercritical technologies with CCS in
the AETA 2012 Model. This was an oversight in the AETA 2012 Model.
The AETA 2012 report identified the thermal efficiency to retrofit subcritical brown and
black coal plants as 21.6 per cent and 30.1 per cent respectively (Table 3.1.2). In the same
table, the efficiency for new build supercritical brown and black coal plants is reported to be
20.8 per cent and 31.4 per cent respectively.
The thermal efficiencies were revised down based on actual operating efficiencies of existing
coal facilities in Victoria and NSW and factored based on the thermal efficiency ratio of new
coal facilities with and without CCS.
A reduction in thermal efficiency is to be expected when applying a retrofit CCS to the plant.
The CCS factor in the following representation refers the efficiency reduction factors for
adding CCS to a coal fired power station. The useful output will reduce from the new
parasitic loads to run the CCS equipment.
Thermal efficiency of existing brown coal plant in Victoria is 26.5 per cent, and the CCS
factor is 0.64. Similarly, the thermal efficiency of existing bituminous coal plant in NSW is
35.5 per cent, and the CCS factor is 0.75
Table 3.1.1 and 3.1.2 of the AETA 2012 report show a reduction is present when comparing
the supercritical with no CCS compared to supercritical with CCS. However, the retrofit case
was only provided for the subcritical technology only and no case was included in the AETA
2012 for a subcritical plant with any CCS.
A review of the values in Table 3.1.2 through comparison to the existing efficiency of
installed black and brown coal fleet in Australia was undertaken. For brown coal the current
17
sent out thermal efficiency is 26.5 per cent for a 500 MW subcritical unit. For supercritical
brown coal without CCS the sent out efficiency is 32.3 per cent. Applying the same reduction
factor the thermal efficiency with CCS retrofitted should be 17 per cent in lieu of 21.6 per
cent as published in AETA 2012 report.
For black coal the current sent out thermal efficiency is 35.5 per cent for a 660 MW
subcritical unit. For supercritical black coal without CCS the sent out efficiency is 41.9 per
cent. Applying the same reduction factor the thermal efficiency with CCS retrofitted should
be 26.6 per cent in lieu of 30.1 per cent as published AETA 2012 report (Table 2).
Table 2: Model Changes, CCS Retrofit Thermal Technologies
AETA 2012 report reference
AETA 2012 model value
AETA 2013 update
Technology 8 Pulverised coal subcritical plant
with post combustion CCS based on brown coal
(retrofit)
Thermal Efficiency
21.6
17.0
30.1
26.6
Technology 12 Pulverised coal subcritical plant
with post combustion CCS based on bituminous
coal (retrofit)
Thermal Efficiency
18
2.1.3 Amortisation period
There was stakeholder consensus that the operating period for all technologies needs to be set
to thirty years and that the construction time is in addition to the operating time. The financial
amortisation period is common for all technologies and is set at 30 years. In the AETA 2012
model, section 2.4 (a) nominates that the amortisation period of 30 years is from the
commencement of construction. The amortisation period has now been changed (Table 3).
Examples of the change are:
Nuclear LWR – GW scale: In AETA 2012 report, amortisation period was 30 years inclusive
of construction and operation. The amortisation period has now changed to 36 years (30
operating and 6 years construction).
Solar parabolic trough: In AETA 2012 report, amortisation period was 30 years inclusive of
construction and operation. The amortisation period has now changed to 33 years (30
operating and 3 years construction).
Table 3: Model Changes, amortisation period
AETA 2012 report reference
AETA 2012 model value
AETA 2013 update
Common Amortisation period
for construction and operation
Amortisation period for
operation includes
construction for all
technologies
Amortisation period for
operation to exclude
construction for all
technologies
2.2 No Carbon Pricing
For the 2013 AETA update, the carbon price modifier has been set to zero per cent as the
base value for the results presented in this report, with the effect of applying a zero carbon
price to all technologies throughout the study period to 2050. The AETA 2013 Model
however, has the option of changing this parameter by the user.
19
3
CONSIDERATION OF OTHER ISSUE S
This section summarises the issues that were discussed during the AETA 2013 Model Update
with AETA stakeholders, but have not led to a change in the model. However, these issues do
not cover the O&M costs considerations that are detailed in section 4.
3.1 Representation of Uncertainty
The recognition of uncertainty within the model was discussed, including both the level of
representation and potential uncertainties with respect to First-of-a-Kind and ‘Early Mover’
Technologies.
A number of factors were identified that lead to uncertainty in estimates – particularly for
emerging technologies. For conventional coal and gas technologies, even though the
technology is mature, the addition of carbon capture introduces cost and performance
uncertainty. Cost estimates have inherent uncertainty due to the market uncertainties and
unforeseeable technological developments and due to:
- Volatility in equipment pricing;
- Volatility in economic conditions (during / post Global Financial Crisis); and
- Volatility in labour pricing due to “other” heavy construction projects in specific areas.
For technologies where the costs are well understood it was considered that the error bars
should be reduced compared to immediate and emerging technologies and that the error bars
should be lower for technology costs in 2012 compared to later years.
There is strong agreement from two key stakeholder submissions with all the factors causing
uncertainty that have been identified in AETA 2012. In particular, the labour cost has varied
(increased) significantly due to large construction projects which have increased costs due to
a shortage of labour and a lower productivity due to less experienced personnel. The
uncertainties provided in the AETA model are available on a per technology and a per
selected year/s basis. BREE will consider whether or not to include more detail on
uncertainty by technology in the 2014 review of the model.
3.2 Application of Learning Curves
It was raised during the consultation process that the AETA model revision could allow for
learning curve cost reduction assumptions to be altered by the end user. This has not been
incorporated in the 2013 update as it is a structural change to the AETA Model.
Stakeholders also raised the question as to whether it is possible within the application of
learning curves to distinguish between the potential for cost reductions on manufactured
components like PV panels versus the Balance of Project (BoP) costs, which may involve
routine assembly and erection activities which are not subject to significant learning by
doing.
However, there are opportunities for cost reductions, particularly where many repetitive tasks
are involved, such as solar field construction, modular construction techniques,
rationalization of components in the BoP design, or reduction in assembly or placement time.
20
This is supported in the US Solar Market Insight Report 2012 (Kann 2012) which identified
continued savings in inverter and racking costs as follows:

“… falling equipment costs and fine-tuning of installation practices have made largescale solar less expensive Q/Q”;

“… with the continuing maturation of the industry, we expect continued focus on
reducing PV balance-of-systems costs (BOS) and that the increased worry over high
penetration PV will drive adoption of 1,000Vdc and advanced inverters,
respectively”; and

“Mounting structure manufacturers noted that the past year has seen tremendous
pricing pressure accounting for price declines of anywhere between 10 per cent and
30 per cent over the past year”.
Given that the balance of plant costs can also be subject to cost reductions, it is not
considered necessary to distinguish learning curves for discrete project costs in the model.
3.3 General Costs Considerations
3.3.1 Fuel Costs
The outlook for fuel costs for gas, coal and carbon was claimed to have materially shifted
since the AETA 2012 model. While there was no evidence provided to support this,
consideration will be given to this issue in the 2014 model update.
3.3.2 CCS Costs
A submission cited the ZeroGen Case Study, and sought to clarify the differences in CCS
cost between ZeroGen and lower values estimated for AETA 2012. This is a valid
comparison however BREE notes the following issues which contribute to explaining the
differences. The international cost component is as follows: AETA 52 per cent / ZeroGen 34
per cent. With the USD exchange rate AETA 1 / ZeroGen at 0.8, adjusting the AETA value
for exchange rate variation would add A$952/kWnet to the AETA value. There is a
difference in plant size with AETA at 557 MW net and Zerogen 400 MW net. A bigger plant
size would typically provide a lower cost / kW installed.
Additionally, section 11.2 of Chapter One of the ZeroGen report advises escalation based on
project delivery from 2011 to 2017. AETA costs are for 2012 basis and do not include
escalation beyond this time. A portion of the Zerogen costs will be inflated over the
comparable AETA cost. Also, section 11.3 of Chapter One of the ZeroGen report identifies
significant enabling works. This is likely to be more inclusive than considered in the AETA
2012 report as identified in section 2.3 (a).
Overall, it is considered likely that a number of estimate basis items in the ZeroGen study are
different and, once equalised, will show a smaller difference between the AETA and
ZeroGen values. Therefore there is no immediate action but the basis and assumptions of the
model may be reviewed during 2014 AETA update.
With regard to CCS efficiency, one submission proposed that the AETA estimates were
overly optimistic. However, no references were cited to support this view and no change has
been made to the model.
21
3.3.3 Opportunit y Costs
A submission was made that footnotes be included regarding retrofit costs to indicate that
make-up power costs are not included. This was not adopted because AETA parameters for
each technology are calculated for that technology alone and do not consider the impact of
reduced output of a retrofit project where additional output needs to be generated from
alternate higher cost generation. Opportunity costs are specifically related to business cases
for specific projects and are not considered for any cases presented in the AETA report.
Moreover, retrofitting does not make electricity generation uncertain or intermittent. It only
lowers the flow of generation at a constant rate (due to lower thermal efficiency) relative to
the non-retrofit case.
3.4 Capital and Construction Costs
A submission was made to update the AETA values for the mid-point capital cost for several
technologies, based on a study provided in support of the submission. The technologies
asserted were:
 IGCC (Integrated Gasification and Combined Cycle) with 90 per cent capture fuelled
with Victorian brown coal;
 IGCC with no capture fuelled with black coal;
 IGCC with 90 per cent capture fuelled with black coal;
 Pulverised Fuel power plant with 90 per cent capture fuelled with Victorian brown
coal;
 Pulverised Fuel power plant with 90 per cent capture fuelled with black coal; and
 OCGT with no capture fuelled with natural gas.
There is a key difference in the magnitude of the labour component in Australia compared
with the labour costs associated with the supporting material (from the USA). While no
changes have been made to the model in this update, the “short term” impact of labour
pricing on technology costs may be considered in further updates.
Similarly, it was submitted that the capital cost values for combined Cycle Gas Turbine
(CCGT) (with and without capture) could be revised. As no documentary evidence was
provided to support this, no change was made.
For Direct Injection Coal Emulsion (DICE) power plant with no capture fuelled with
Victorian brown coal, it is also suggested that the values be reviewed, with a number of
papers provided for reference. However, these papers do not address capital cost in any depth
and it is unclear if the balance of project costs included are comparable with AETA. DICE
technology is not mature and is probably best described as in the demonstration to
deployment phase of development which brings uncertainty into the cost analysis. Therefore,
data is needed to substantiate this submission. As this was not available at the time of
preparing this report, consideration of this issue is deferred to a later time when the necessary
data is available.
An increase in the capital costs for Solar thermal trough (6 hrs storage) and Solar thermal
central receiver (6 hours storage) were proposed, based on a supporting study by the Electric
Power Research institute (EPRI). The proposed values are substantially larger than the AETA
22
2012, but it is not clear what basis is used to generate these revised values. A separate
submission received from another AETA stakeholder has supported the AETA values.
Additionally, the cited reference for solar thermal trough the Energy Power Research
Institute (EPRI) plant configuration is based on air cooling – while for AETA, the plant
configuration assumes water cooling. The difference in plant configuration will account for a
small part of the difference. The AETA value is based on a reference report as issued in 2012
by the US National Renewable Energy Laboratory (NREL 2012).
The AETA value for the central receiver technology is based on a small (20MW) plant
(Gemasolar) with factors for adjustment to field size for thermal storage capacity and post
FOAK learning. These factors will align with increased uncertainty in the AETA value. It is
likely that additional cost information may now be available for the Brightsource Ivanpah
plant (no storage) and other tower plants being considered / under construction.
Further investigation of these issues has been sought with stakeholders but is, as yet
unavailable.
Another suggestion was made to consider capital costs on a component basis. The capital
costs used in AETA 2012 for existing technologies were based on actual costs that could be
sourced on published documents (locally and/or internationally) or from WorleyParsons
internal data. For developing technologies, costs were not considered on a component level.
For this reason, in technologies that are not commercialised a number of assumptions would
need to be made which may limit ‘real’ costs being available. No change to the model arose
from this submission.
A reassessment of the construction expenditure profile for concentrating solar power (CSP)
technology options was sought in another stakeholder submission, and supported by a
referenced report (IT Power 2012). However, the plant sizes considered in the AETA report
are larger capacity (100 MW+) than those discussed in the cited report, and consequently
have a longer duration construction period. As three years is considered to be an appropriate
time period to spread the construction expenditure profile, no change to the model was made.
3.5 Costs Associated with Solar Technologies
A change to the model was sought with regard to the significant downward trends in the cost
of solar PV. The stakeholder submission cited pricing data from the Australian Photovoltaic
Institute (APVI). Consultation with the APVI identified that evidence based information for
utility scale PV costs in Australia is limited because Australia has no PV systems 100 MW or
larger. It is acknowledged, however, that there is significant and continued volatility in the
solar PV market including volatility due to competition / oversupply in the PV module
market as well as continued price reductions for balance of system and installation costs.
A$3.38 /Wnet was a reasonable valuation for 2012 AETA. The AETA 2012 value will be
maintained but may be reviewed in the 2014 model update.
It was also suggested that solar thermal costs could be better represented in the model by
allowing for different periods of storage rather than a standard 6 hours. The AETA 2012
scope was based on fixed plant designs which included fixed thermal storage sizing where
thermal storage was included. With thermal storage there are a number of variables that can
be considered including differing field sizes (solar multiple) as well as actual thermal storage
capacities. This is likely to add significant complexity to the report and to the model, the
benefit of which at this stage does not warrant the changes.
23
3.6 Costs Associated with Nuclear Technologies
It was submitted that consideration be given to including the impact on LCOE for nuclear
technology of the relatively high insurance costs for nuclear technologies. This issue will be
considered in the 2014 review of the AETA model. However, insurance costs or plant
decommissioning costs are not considered for any of the 40 AETA technologies.
Also, the O&M improvement rate for Nuclear was not reconsidered as there is no O&M
improvement rate for Nuclear in the model.
3.7 Further Technologies
A proposal was received which recommended that further technologies (DICE power plant
based on black coal with and without capture, and DICE brown coal with capture; and
medium speed DICE technologies) be incorporated into the AETA Model. However, as
mentioned earlier, this update of the AETA 2012 Model only considered the technologies
included in that model. This update of the model is not intended to broaden the technologies.
3.8 Auxiliary Loads
Another example used for the purposes of drawing comparisons with the AETA model was
the SaskPower Post Combustion Retrofit. It is difficult to distil the SaskPower project data
into a direct comparison with the AETA study and consequently there is insufficient data
certainty to warrant changes to the AETA 2012 values. The SaskPower Post Combustion
Retrofit was also cited as to its conservative auxiliary loads for brown and black coal.
However upon further investigation this was not substantiated within the SaskPower
example.
24
4
WIND, PV AND CSP OPERATI ONS AND MAINTENANCE (O&M)
COST UPDATE
4.1 Operation and Maintenance Costs
O P E R A T I N G A N D M AI N T E N A N C E C O S T D E F I N I T I O N S
In considering the costing of O&M, there is no absolutely clear definition of which costs
should be considered as fixed and which variable, with the breakdown varying based on a
range of issues including technology, location and resource type. For this reason, in the future
AETA reports O&M costs may be compared in terms of annual total operating expenditure
(OPEX) per MW of generation. This method is widely used by most international institutions
to analyse O&M costs and to avoid subjective considerations.
For this report, fixed and variable costs are reported to provide direct comparison with AETA
2012. In this regard, in general, fixed costs are independent of the electrical generation of the
plant and are expressed as annual cost per MW capacity. Fixed costs include items such as:
 fixed labour;
 equipment; and
 vehicles.
Variable costs are proportional to the electrical generation of the Plant and are expressed as
cost rate per kWh energy output. Variable costs include items such as:
 variable labour;
 consumables; and
 spare parts.
As both public and private domain material vary in the way they approach and report on
fixed and variable maintenance, within the following text where an interpretation has been
used for comparison purposes, this is described.
A submission was made to remove the operations and maintenance (O&M) cost escalation
factors. This was not taken up as there is an increase in the O&M costs over CPI, which is
borne out historically. A review of the basis for this escalation determined that the
underlying assumptions were appropriate. The review also considered adopting a generic
learning curve approach for O&M improvement rates, as was suggested in one submission.
This was not adopted as the model has an O&M improvement rate (set at 0.2 per cent per
annum) which can be varied by the user for wind and solar technologies. This value accounts
for more efficient practices balancing the increase in labour and material costs over and
above CPI. However, changes to O&M improvement rates for selected technologies were
made, as mentioned earlier. O&M improvement rate values may be further considered for
emerging technologies in 2014 AETA study.
A number of submissions referred to the improvement rate of O&M costs, with evidence for
existing technologies to support these rising at 150 per cent CPI. It was suggested that for
25
developing technologies it could reasonably be assumed that there would be reductions in
O&M between the first commercial installation and subsequent installations.
While it is generally acknowledged that the LCOE of delivered energy from wind is falling,
within the literature there is conflicting evidence around trends in O&M costs, with recent
reports indicating both significant decreases and increases in O&M (see section 4.3.2).
Solar thermal plants consist of technology components that can be considered mature (e.g.
steam turbine) and components that are undergoing further development such as the solar
field and thermal storage. Solar thermal plants require manning for operation as opposed to
wind turbines that do not require the same level of manning.
A recent article (Muirhead 2013) advised for the Solar Energy Generating Systems (SEGS)
plants in California that have been operating since the early 1990’s: “My understanding is
that the performance of the SEGS plants has significantly improved over time. This is due
primarily to replacement of first generation receivers with newer receivers that are much
more efficient. O&M practices at the plants have also improved over time based on the now
long history of operating these plants, resulting in increased output in addition to reduced
O&M costs."
In the AEMO report 100 Per Cent Renewables Study - Draft Modelling Outcomes Scenario 1
assumes that rapid technology transformation will drive real reductions in O&M costs
outweighing any increases projected in the AETA 2012, so O&M costs reduce by 12.5 per
cent by 2030 and 25 per cent by 2050. Scenario 2 uses the AETA 2012 assumption that
O&M costs escalate at around 150 per cent of Consumer Price Index (CPI), which leads to
cost increases of 27 per cent by 2030 and 46 per cent by 2050. It should be noted that the
Scenario 1 reductions are assumptions without further analysis of what will bring the
assumptions to fruition.
In AETA 2012, the common O&M improvement rate for most technologies is set at 0.2 per
cent and can be varied as a user input. The O&M improvement rate for emerging
technologies, solar thermal and photovoltaic technology options and offshore wind, is set to
2.5 per cent and can also be varied as a user input. The improvement rate is now compounds
on the previous year’s value.
The O&M improvement rate values may be further considered for emerging technologies in
2014 AETA study.
4.2 Operating and Maintenance (O&M) Changes in summary
As part of the Model Update, special emphasis was placed in this report on the Operational
and Maintenance (O&M) costs and O&M improvement rates for all wind, solar thermal and
solar PV renewable technologies covered in AETA 2012. As mentioned earlier, this took into
account relevant Australian and international reports, public domain information, private
sources as well BREE and WorleyParsons’ in-house experience. The updated O&M values
are shown in Table 4. Reductions in CSP O&M costs of between 8 per cent and 27 per cent
were obtained in comparison to values provide in AETA 2012 report.
The review included a detailed review of a report by IT Power cited as part of one of the
stakeholder submissions. In that report reference is made to a case where $18/MWh of O&M
costs comes from 64MW trough plant, however it does not specify the relevant location, hour
26
of thermal energy storage (TES), capacity factor, type of cooling, and back-up fuel, and
therefore cannot be fully analysed nor used towards this AETA update.
O&M costs for solar thermal plants are significantly affected by the costs of manpower. To
demonstrate this with an example, $18/MWh for a 100MW plant with a 23 per cent capacity
factor (the IT Power report consideration) would result in an annual O&M cost of
approximately $3.6 million. A 100MW plant will need at least 28 full time employees to be
properly manned 7 days/week as there needs to be multiple shifts. With this amount of
labour there are insufficient funds for site services, utilities and materials/maintenance. If the
value is based on another location, such as the Far or the Middle East region, where labour
costs are significantly lower, then a lower O&M cost may be feasible, however for Australia
this does not appear to be feasible.
The changes to O&M values for the 2013 AETA model refresh are summarised below.
Table 4: Model Changes, O&M costs
AETA 2012 report reference
AETA 2012 model value
AETA 2013 update
O&M improvement rate maintained at
0.2per cent for:
 Coal based technology options
 Gas based technology options
 Solar thermal hybrid options
 Onshore wind
 Biomass technology options
Section 2.3 Technical Assumptions
Operating and Maintenance Cost
Estimates
 Wave technology options
O&M improvement rate 0.2per
cent all technologies
 Geothermal technology options
 Nuclear technology options
O&M improvement rate changed to 2.5per
cent for:
 Solar thermal technology options
 Photovoltaic technology options
 Offshore wind
The O&M improvement rate is compounded
from the previous years’ value.
Section 3.3 Solar thermal
technologies
Solar thermal - Parabolic Trough w/o
storage
Fixed O&M (AUS$/MW/year)
Variable O&M (AUS$/MWh)
60,000
59,176
15
15.19
65,000
72,381
20
11.39
Solar thermal - Parabolic Trough with
storage
Fixed O&M (AUS$/MW/year)
Variable O&M (AUS$/MWh)
Solar thermal - central receiver
technology w/o storage
27
AETA 2012 report reference
Fixed O&M (AUS$/MW/year)
AETA 2012 model value
AETA 2013 update
70,000
58,285
15
7.07
60,000
71,312
15
5.65
Fixed O&M (AUS$/MW/year)
60,000
64,105
Variable O&M (AUS$/MWh)
15.00
15.19
65,000
72,381
20
11.39
Variable O&M (AUS$/MWh)
Solar thermal - central receiver
technology with storage
Fixed O&M (AUS$/MW/year)
Variable O&M (AUS$/MWh)
Solar thermal - Linear Fresnel w/o
storage
Solar thermal - Linear Fresnel with
storage
Fixed O&M (AUS$/MW/year)
Variable O&M (AUS$/MWh)
Section 3.5 Photovoltaic
technologies
PV – non tracking
Fixed O&M (AUS$/MW/year)
25,000
25,000 (no change)
PV - Single Axis Tracking
Fixed O&M (AUS$/MW/year)
38,000
30,000
47,000
39,000
40,000
32,500
12
10
80,000
77,600
12
30
PV - Dual Axis Tracking
Fixed O&M (AUS$/MW/year)
Section 3.6 Wind Technologies
Wind Onshore
Fixed O&M (AUS$/MW/year)
Variable O&M (AUS$/MWh)
Wind Offshore
Fixed O&M (AUS$/MW/year)
Variable O&M (AUS$/MWh)
4.3 Wind
4.3.1 Introduction
This Section reviews onshore and offshore wind operations and maintenance (O&M) costs
used in AETA 2012. The values scrutinised are the fixed and variable O&M given in Table
3.6.1 of that report, summarised in Table 5 below.
28
Table 5: Wind O&M costs used in the AETA 2012 report
Option
Fixed O&M (AUS$/MW)
Variable O&M (AUS$/MWh)
Onshore
40,000
12
Offshore
80,000
12
O&M covers all of the services required to keep the wind farm operating as contracted to
supply energy and renewable energy certificates, for its lifetime, inclusive of:
 turbines and all balance of plant (roads, buildings, electrical equipment, SCADA /
control equipment) up to the high voltage connection point on the wind farm
substation;
 labour (both trades and professional);
 facilities (workshops, stores, offices);
 equipment (tools, jigs, vehicles, rigging, safety equipment, craneage);
 spare parts; and
 consumables (such as oil, grease and office consumables).
Windfarm size was not specified in AETA 2012, however it was noted that wind farms
greater than 100MW are becoming more common. Since then, within Australia, wind farms
of larger and smaller sizes have been constructed; for example, the 420 MW Macarthur Wind
Farm in Victoria and the 55 MW Mumbida Wind Farm in Western Australia, with both larger
and smaller wind farms under proposal. For this review, a nominal size of 100-150 MW is
used as representative of current and future facilities.
4.3.2 Review of Evidence
As mentioned earlier, the review of public literature by BREE and WorleyParsons, the
procurement of private studies, consultations with owner/operators in the wind farm O&M
sector in Australia, AETA Stakeholders, and project Steering Committee members were used
to assist the current Model Update process. Where possible, these sources are noted in the
text, however, some of these sources have asked to remain anonymous and where so, the
term “private source” has been used.
As noted by one reviewer in NREL 2011, O&M cost information in the public domain in
both quantum and quality is poor and the situation appears no better in 2013, particularly in
the discrimination of fixed and variable costs. One reason for this is the commercial and
increasingly competitive nature of the sector with wind farm O&M now a significant
business worldwide with subsequent confidentiality around actual costs.
What constitutes wind farm O&M is also changing. This is driven, in part, by technological
change as the wind fleet ages, as new turbines become larger and more sophisticated,
particularly offshore. Competition in the provision of O&M services is also changing with
maturing of the wind energy product. As an example, the following industry trends are now
evident:
29
 a growing role of independents in the wind O&M market – around 25 per cent of the
wind fleet in the US is expected to be operated and maintained by independents by
2025 (Ebert and Ware 2013) as opposed to original equipment manufacturers (OEMs) wind is largely a commodity market and easier for new participants to enter, something
not necessarily seen with other generation technologies;
 tighter supply markets – general economic volatility is tightening the supply and
project development chain for wind, moving interest into the O&M sector, bringing
price volatility and more competition;
 a more sophisticated asset management model – where O&M providers are linking
operational data with long term condition monitoring, output forecasting and work
order scheduling to deliver what is termed “lifecycle optimisation”, squeezing more
energy out of the asset;
 older turbines exceeding planned maintenance budgets – with the chief issue being
keeping the variable O&M from unforeseen breakdowns;
 a push for larger turbines, particularly offshore (5-10 MW) and in deeper waters; and
 linking O&M to turbine contracts – there is evidence (including in Australia, private
source) that wind farm O&M is becoming an even more significant bargaining
component of turbine supply contracts, where lower supply costs are balanced by
longer O&M contracts.
Costs of wind O&M are difficult to summarise as they are dependent on many issues. As just
one example, in the NREL 2011 study cited earlier, a wide variability in wind farm O&M
costs was found across a range of countries (Figure 1). This reference demonstrates this
variability from the average reference case in terms of Levelised Cost of Energy (LCOE).
30
Figure 1: Effect of country variables on LCOE of wind plant
Source: NREL (2011)
Other issues which affect the contracted cost of O&M for wind include:
 regional variations in labour and transport costs;
 wind farm environment, particularly wind regime and proximity to the ocean
(corrosion);
 the maturity and availability of wind turbine technicians;
 the spread of facilities geographically and the wind farm asset sizes in a portfolio;
 the turbine type and brand, particularly the support establishment within a Region;
 the age of the asset, O&M history and existence of Type (or systematic) failures of
major components;
 the ability of the O&M provider under the contract to source third party spares and/or
try varied maintenance practices; and
 the nature of the O&M contract – for example, does it include risk / reward elements or
have a link to the wind turbine supply contract, or is it a “production availability”
contract type.
While it is generally acknowledged that the LCOE of delivered energy is falling for wind
technology (Hand 2013), within the literature there is conflicting evidence around trends in
O&M costs, with recent reports indicating both significant decreases (BNEF 2013) and
increases (Ebert and Ware 2013). It is generally acknowledged that increased competition in
the O&M market is delivering lower cost service provision, but this may in part be offset by
an ageing fleet requiring more variable maintenance, and a more sophisticated and costly
31
response. Several studies have demonstrated that the costs of maintaining wind turbines
generally increase with time, following a trend similar in shape to that in Figure 2 (Hand
2013), with estimates in Albers (2009) indicating a doubling in turbine O&M costs by mid
plant life. The term, COD, in Figure 2 refers to commercial operations date.
Figure 2: Typical cost increasing trends in wind farm O&M costs with commercial operations
date
Source: Adapted by WorleyParsons from Houston (2013)
In Australia, this trend is also evident in post 10-year aged machines (private source),
particularly in relation to variable maintenance. The nature of any similar increase with more
modern turbines is unpredictable, although turbine availability is improving and there is
evidence that O&M costs with each generation of turbine are lowering, see Wiser et. al.
(2012).
The O&M costs for offshore wind farms are particularly difficult to estimate as the industry
is still at the early stages of development, including the progression of much larger turbines
into deeper water, and the more complex nature of the task. Such progression is indicated in
Figure 3, taken from RolandBerger (2013), which indicates an expected decrease in O&M
costs. These costs are of the same order of that published in other recent publications, UK
Crown Estate (2012) and US DoE (2013).
32
Figure 3: Trends in offshore wind farms and estimated impact on LCOE
Source: RolandBerger (2013)
4.3.3 Updated O&M Figures for Australia
It is not a simple matter to transfer international costs to Australia as, despite trends, there are
significant differences between regions, including:
 size of market – despite growth, the Australian wind market is small with respect to
other world regions. For example, the total wind fleet is 4 GW (CEC 2013) for
Australia versus 60 GW for the US (AWEA 2013);
 labour and material rates in certain parts of Australia are high by world standards;
 the logistics of getting to and within Australia generally involve longer distances than
other areas of the world, particularly due to the remoteness from major equipment
suppliers;
 volatility of the Australian dollar particularly against the US; and
 the size of Australian wind farms tends to be larger.
These differences can be seen in Figure 4, supplied by a turbine equipment supplier (private
source) and showing the relative O&M costs (per MW) and technician numbers (per 100
MW) across various world regions in 2012 for wind turbine maintenance only and excluding
balance of plant. Numbers and scales between the two indices have been removed to protect
the confidentiality of this supplier, with data believed to cover the entire global portfolio
under management. This shows a significant difference between regions for onshore in both
indices, for example almost a 45 per cent difference in costs between Europe and America.
Australia would sit within “Asia/Pacific”, and while the Figure indicates generally lower
O&M costs and higher technician numbers for this region, this presumably covers a very
diverse area (including South East Asia, New Zealand and Oceania) which may skew results.
33
Unlike many larger global markets, the wind O&M sector in Australia is dominated by
turbine equipment suppliers, with original equipment manufacturer (OEM) contracts
estimated to cover more than 95 per cent of the fleet. The evidence for this is mostly
anecdotal, although a number of smaller independent suppliers are now known to be
undertaking full service O&M for older plant (>10+ years) with many of the drivers for this
covered in Ebert et. al. (2013). There is also evidence (private source) that wind turbine
suppliers in Australia are seeking O&M contracts with much longer terms and tying these to
reductions in turbine supply prices. This may indicate a lack of competitive pressure on
O&M pricing in the near to mid-term, and as the size of the overall market is small, it is
unknown whether independents will grow market share as has been the case in many larger
global markets; see for example Deloitte & Touche (2012).
The most recent contemporary literature comments on onshore wind farm O&M pricing in
Australia and surrounds, that could be found in the public domain and not used for the AETA
2012 work, are from Hassan (2011) and Deloitte (2011). These are summarised with other
new international references cited in Table 6, with assumptions on any conversions noted
below the table. As no offshore wind farm projects have been progressed in Australia, the
table includes values from new sources for offshore projects from the international public
domain literature - the significant difference to onshore costs is evident in the values.
Figure 4: O&M Costs (per MW) and Technician Numbers (per 100MW) for total wind turbine
O&M (Opex)
Source: Private - values and scales removed to protect confidentiality
From Table 6 and considering the differences in markets, it appears that for onshore wind the
AETA 2012 estimates may be slightly high, with an updated AETA 2013 recommendation
given in Table 7. This value has been arrived at by considering:
 the size of the Australian wind market and lack of competitive pressure from
independent O&M service providers;
34
 supply side pressures on OEMs, driving them to protect their O&M businesses and
lowering costs;
 the likely increase in fleet installations to comply with RET legislation, skewing the
fleet age to more a modern generation of turbines although it is noted that there is some
uncertainty around long term O&M cost trends, particularly variable maintenance – an
asset age of around 5 years is assumed here;
 uncertainties in what is included in referenced values and differences in markets; and
 advice from actual asset owners and O&M providers (private sources) on current actual
costs.
Onshore
Table 6: Comparison of AETA 2012 wind O&M estimates with new references for 2013
Source
Region
AETA 2012
Australia
Houston 2013
BNEF 2013
Variable O&M
Total OPEX
(AUS$/MW)
(AUS$/MWh)
(AUS$/MW)
40,000
12
79,9451
US
-
-
35-38,0002
Global
-
-
25,0003
Australia
-
-
70,000
Australia
-
-
55,000
Hassan 2011
Australia
-
-
83-99,0004
Deloitte 2011
New Zealand
-
-
45,0005
AETA 2012
Australia
80,000
12
126,2526
Crown Estate 2012
UK
-
-
275,0007
Hassan (2013)
UK
-
-
239,1567
RolandBerger 2013
Europe
-
-
198,0008
US DoE 2013
US
-
-
144,9709
Private Source (2013) (> 10 yr old
plant)
Private Source (2013)
(< 2 yr old, out of warranty plant)
Offshore
Fixed O&M
1
Assumes a 38% capacity factor
US//AUD = 1.09, extrapolated from Figure approximately to 2013
3
EURO//AUD = 1.42, uncertain if this includes all balance of plant or VOM, and only includes OEM providers
4
Assumes a 38% capacity factor
5
Assumes NZ//AUD = 0.84, a 38% capacity factor and the mid-range estimate for O&M
6
Assumes a 44% capacity factor
7
Assumes GBP//AUD = 1.67 and taking midpoint of estimates stated
8
Assumes GBP//AUD = 1.67 and taking value for 3MW turbines
9
Assumes US//AUD = 1.09
2
35
The figures shown for onshore projects in Table 7 represent a 15 per cent decrease in the
expected O&M costs of wind farms in Australia compared to AETA 2012. This change
reflects the volatility in this market noted in previous sections and in referenced material
internationally, plus the appearance of significant downward pressure on wind O&M prices
primarily through increased global competition. The values allow for the rising price of
turbine O&M as the turbine ages during its life.
For offshore wind, it appears that the O&M costs in AETA 2012 are too low, and although it
is tempting to align costs with the most recent US figures due to their lower costs and similar
coastal conditions to Australia, the European offshore fleet is significantly larger and more
mature. Average figures across the 2013 referenced material including Europe is
recommended. This is also shown in Table 7 and represents a significant increase in estimate
costs (around 33per cent), which reflects this evolving sector.
There is very little contemporary information available on the breakdown of fixed and
variable maintenance on wind plant making judgment around this for the AETA requirements
is difficult. However, there is some published but copyrighted material, eg. GlobalData 2012,
which, combined with others (private sources), indicates that for onshore and offshore wind
plant respectively a 50/50 and 40/60 FOM / VOM split is appropriate. This has been used to
adjust the total OPEX figure in Table 7 to the AETA scheduled and variable indices
requirements, using a 38 per cent and a 44 per cent capacity factor for onshore and offshore
projects respectively.
Table 7: Recommended AETA (2013) values
AETA (2013) update
Fixed O&M
Variable O&M
Total OPEX
(AUS$/MW)
(AUS$/MWh)
(AUS$/MW)
Onshore
$32,500
$10
$65,790
Offshore
$77,600
$30
$194,000
4.4 Solar Photovoltaics (PV)
4.4.1 Introduction
This Section of the report focuses on the O&M costs for ground-mount photovoltaic (PV)
technologies broken down by the following mounting system configurations:
 Fixed Tilt (FT)
 Single Axis Tracking (SAT)
 Dual Axis Tracking (DAT)
Although different PV panel technology types (eg poly-crystalline, mono-crystalline, or thin
film CdTe) affect the capacity factor and land use, the O&M costs are comparable. The
estimates for this Report are based on polycrystalline PV technology which provides an
average cost on a per Watt basis, with mono-crystalline O&M costs being slightly lower and
thin film O&M costs being slightly higher.
With the aim to provide comparable results between technologies, WorleyParsons has
analysed and updated the PV O&M costs in terms of both fixed operation and maintenance
36
costs (FOM) and total operating expenditures (OPEX) based on reference plants of similar
characteristics.
Assumptions, interpretations and considerations based on their in-house data and global
market trends are described in the following Sections.
4.4.2 Review of the Evidence
Since the AETA 2012 report release, few new public domain reports related to O&M costs
for PV systems have been published. To confirm this, the following organisations have been
consulted by WorleyParsons to provide the 2013 O&M costs update for the selected PV
configurations:
 International Renewable Energy Agency (IRENA) (www.irena.org);
 International Energy Agency (IEA) (www.iea.org);
 The World Bank (WB) (www.worldbank.org);
 The US National Renewable Energy Laboratory (NREL) (www.nrel.gov);
 Solar Energy Industries Association (SEIA) (www.seia.org.au);
 European Photovoltaic Industry Association (EPIA) (www.epia.org); and
 Solar Electric Power Association (SEPA) (www.solarelectricpower.org).
Upon review of the available information when compared to AETA 2012, the listed
organisations do not have any new public information related to large-scale PV O&M costs.
If O&M costs are mentioned, they are normally referenced as a per cent of the total Capital
Expenditure (CAPEX) for the plant (around 1 per cent), and provide little useful information
about O&M Cost changes.
Due to insufficient detailed and recent information in the public domain, WorleyParsons
obtained the following market reports from Photon, a private organisation focused on market
news, political discussions, and technology analysis for the PV industry:
 Photon 2013, “The True Cost of Solar Power - Temple of Doom”; and
 Photon 2013, “Solar Annual 2013 - Build your Empire”
These private reports had minimal focus on O&M costs. To provide further input in this
area, private O&M service providers were contacted for pricing estimates and market trends.
4.4.3 AETA 2012 O&M PV costs report comparison
Typical power plant O&M costs are expressed as a combination of a variable component
(proportional to generation), and a fixed component (occurs irrespective of generated output).
Since the generation of a PV plant is dependent on solar radiation (not requiring fossil fuel or
water which make up the major components of variable costs for conventional generation), it
is typical to express the O&M costs only as Fixed O&M (FOM) costs proportional to the
plant size due to the simplicity of PV systems. The AETA 2012 report follows this practice
and estimates the PV O&M costs as FOM only relative to plant size (kW) expressed on a per
year basis.
37
In order to facilitate comparisons of these costs with other electricity technologies, the FOM
costs in the AETA 2012 report are also presented as OPEX costs per MW of generating
capacity per year.
AS S UMPTI ON S AND C ON SID ER ATI ONS
The following costs are included in the FOM estimates as an annual cost per kW capacity;
 labor and administrative expenses;
 panel washing (twice per year at $300 / kl for water);
 weed abatement (seasonal herbicide applications);
 inverter replacement reserve (replaced at operational year 10); and
 materials and maintenance: spare parts, civil works, preventative and corrective
equipment maintenance.
Although the cost of water is variable depending on location and usage, it is such a small
portion of the total O&M costs that it is adequate to assume it as a fixed cost using the
assumptions listed above.
AET A 2012 PV O&M C O S T S C O M P A R I S O N R E P O R T
The technical characteristics of the reference PV plants used in the AETA 2012 report have
been extracted from the AETA 2012 Model (Version 1_0 Rev B, BREE 2012) and are
summarised in Table 8.
Based on this information, the following parameters for the PV technologies are estimated:
 Total net energy production in terms of MWh sent out per year;
 Total plant acreage;
 FOM in terms of USD per year; and
 Total OPEX costs in terms of USD per year and USD per total net energy production
per year.
38
Table 8: AETA 2012 reference plants technical characteristics and OPEX costs
Plant Characteristics
Units
Fixed Tilt (FT)
Single Axis
Tracking (SAT)
Dual Axis
Tracking (DAT)
Plant Characteristics
Plant Net Capacity
MW
100
100
100
Capacity Factor
per cent
21
24
26
FOM
$/kW/year
25
38
47
Net Energy
MWh/year
183,960
210,240
227,760
Plant Acreage
acres
500
800
900
Total FOM
$/year
2,500,000
3,800,000
4,700,000
Total OPEX
$/year
2,500,000
3,800,000
4,700,000
$/kWh
0.0136
0.0181
0.0206
Total OPEX
Total OPEX costs are between 0.0136 and 0.0206 USD/kWh as shown in Table 8 above.
These values are conservative cost estimates, but reasonable for a large-scale PV plant with
comprehensive O&M service. As is expected, the FOM or OPEX costs increase as the plant
footprint increases and the complexity of the mounting system increases. However, the
increases to single and double axis tracking technologies are larger than would be expected.
The increased complexity of the trackers does add costs to O&M in terms of labor, parts, and
even physical plant size, but these additions are minor in comparison to the larger O&M
budget items such as the inverter replacement reserve and general electrical maintenance,
which are irrespective of mounting system.
These values, although conservative, still show the cost reductions from the industry learning
curve and expanded competition over the past few years when compared to past estimates of
O&M costs. This can be seen in the following Table 9 of Fixed Tilt (FT) costs which
provides some estimates found in previous publications by IEA (2008) and EPRI (2010). The
tracking estimates are not shown since minimal data is available. This corresponds to the
historical market trend of the industry being more willing to install fixed tilt systems rather
than tracking systems due to lower costs and technology risk.
Table 9: Comparison of historical estimated PV and O&M costs in the public domain
PV Configuration
Fixed Tilt (FT)
O&M Costs
Units
IEA 200810
EPRI 2010
AETA 2012
FOM
$/kW/year
40
32 to 37
25
* values in Italics are derived from reported data
10
Report assumed 1% of capital costs and 23% capacity factor
39
4.5 AETA 2013 PV O&M Costs Update
Using the same plant characteristic assumptions as the 2012 AETA Model, the 2013 O&M
costs were estimated by WorleyParsons based on the references described in review of the
evidence in Section 4.4.2. The comparison of the AETA 2013 and 2012 O&M costs are
presented in Table 10 below.
Table 10: 2013 PV O&M costs compared to 2012 PV O&M costs
PV Configuration
O&M Costs
Units
Fixed Tilt (FT)
FOM
$/kW/year
OPEX
$/kWh
FOM
$/kW/year
OPEX
$/kWh
FOM
$/kW/year
OPEX
$/kWh
Single Axis Tracking (SAT)
Dual Axis Tracking (DAT)
AETA 2012
WorleyParsons
2013 Update
25
25
0.0136
0.0134
38
30
0.0181
0.0141
47
39
0.0206
0.0173
Although the O&M costs for FT systems are approximately the same, SAT and DAT O&M
costs reduced by around 20-30 per cent in this 2013 update compared to the AETA 2012
report. The consistency of the FT costs is reasonable and expected to continue for the next
few years as discussed further in Section 4.5.1.
Regarding the SAT and DAT costs, although there have been improvements in the design of
trackers for PV applications, this O&M cost reduction is due to a better understanding of the
costs associated with electrical and tracking system maintenance. The cost differences
between tracking systems was corroborated by quotes from private O&M service companies
who indicated that there was only a slight increase in costs from FT to SAT, but a larger
increase in costs from SAT to DAT.
As compared to the references mentioned in Section 4.4.2, the updated cost estimates are
conservative. Table 11 compares the estimated 2013 O&M costs with those references.
However, since these publications focused primarily on the CAPEX with very general O&M
cost assumptions, the O&M costs presented therein are not considered representative
baselines for large-scale solar projects. Furthermore, they attest to the industry’s tendency to
focus strictly on installation costs and not lifecycle costs which is discussed further in Section
4.5.1.
40
Table 11: 2013 updated O&M costs compared to new referenced O&M costs (7-2)
PV
Configuration
O&M
Costs
Units
Fixed Tilt (FT)
FOM
$/kW/year
OPEX
$/kWh
FOM
$/kW/year
OPEX
$/kWh
FOM
$/kW/year
OPEX
$/kWh
Single Axis
Tracking (SAT)
Dual Axis
Tracking (DAT)
WorleyParsons
2013 Update11
NREL
201312
IRENA
2013a13
Photon
201314
Private O&M
Service Providers
201315
25
23.5
17 to 21
18
17 to 23
0.0134
0.0216
to
0.0383
Not
provided
0.0121 to
0.0266
0.0098
0.0094 to 0.0127
Not
provided
Not
provided
25 to 27
0.0141
Not
provided
Not
provided
Not
provided
0.0136 to 0.0147
39
Not
provided
Not
provided
Not
provided
32 to 34
0.0173
Not
provided
Not
provided
Not
provided
0.0174 to 0.0185
30
* values in Italics are derived from reported data
4.5.1 O&M Learning Rates
In the rapid PV industry growth of the last three years, WorleyParsons and anecdotal
experience is that PV was considered generally to require little to no maintenance, causing a
general disregard for O&M planning. This appears to have resulted in complications as
owners struggle to resolve reliability, performance, and budget issues as the projects mature
(multiple private sources). Although the maintenance costs are smaller compared to standard
power plants, O&M awareness has been increasing in the industry and, therefore, the O&M
cost estimates have subsequently increased.
This is supported through the recent focus of O&M at PV conferences (such as Sandia
National Laboratory and Solar Energy International events) on increasing the investment in
O&M practices, in addition to improving the current practices, products, and services, so that
PV plants can be better maintained to achieve higher reliability throughout the plant life
cycle. Currently, the majority of O&M expenses for PV systems consist of maintaining and
replacing the inverters, followed by the Balance of System maintenance. In general, once the
appropriate level of investment in O&M for PV is reached, then O&M costs will begin to
decrease as the following issues develop to maturity:
 technology improvement;
 inverter design for reliability and longevity
 data monitoring for preventative and corrective maintenance support
 system efficiency to increase system output for the same O&M expense
 decreased capital costs for major equipment
 decreased spare parts costs;
11
See assumptions in Section 4.3.3 and 4.4.3
12
Report assumed 250kW rooftop at 7 to 10% capacity factor
13
Report assumed 1% of CAPEX and 9 to16% capacity factor
14
Values derived from the global weighted average calculations assuming 21% capacity factor and 20 year lifecycle. Report assumed a
simple percentage of average selling price
15
Quote excluded weed abatement, panel washing, and inverter replacement reserve which were supplemented from the WP estimate.
Calculations assumed 21% capacity factor.
41
 industry maturity and stability;
 reliable OEM support from product consistency and commercial stability
 improved codes and standards for PV equipment, system design, installation,
commissioning, and O&M; and
 experience
 trained and experienced personnel in the installation and maintenance of PV plants.
In line with this trend, owners, system designers, installers, and OEMs are now including
O&M considerations in their finances, designs, services, and products. Even though there
have been, and will continue to be, cost reductions in O&M due to the industry maturation,
stabilization, and competition, those cost reductions are balanced with the necessary
increases in O&M investment to meet the maintenance needs of existing and planned PV
plants, resulting in a level O&M cost estimate for the next five years.
Photon (2013) follows this assumption of consistent O&M costs for the next ten years as well
as WorleyParsons discussions with O&M service providers. Therefore, the assumption that
PV O&M costs will remain somewhat constant over the next five years before reducing again
appears to follow the projections in the industry.
4.5.2 Conclusions - PV
The key findings from the AETA 2012 review and update of the PV O&M costs are as
follows:
 The 2013 WorleyParsons PV O&M costs update resulted in values of
 $25/kW/year for FT systems
 $30/kW/year for SAT
 $39/kW/year for SAT in 2012 USD;
 Fixed tilt configurations have not seen significant changes in O&M costs compared to
the 2012 AETA estimates while SAT and DAT configurations cost estimates have
reduced approximately 20-30 per cent based on a better understanding of the associated
O&M costs;
 Values obtained in the 2013 WorleyParsons update are more conservative, but are
aligned with values provided by recognised international institutions, even though few
detailed O&M breakdowns are available; and
 O&M costs for PV are expected to remain constant over the next five years before
reducing as the industry matures in both experience and long-term planning
capabilities.
42
4.6 Concentrating Solar Pow er (CSP)
4.6.1 Introduction
This Section of the report focuses on the O&M costs for the following Concentrating Solar
Power (CSP) technologies:
 Parabolic Trough (PT);
 Solar Tower (ST); and
 Linear Fresnel (LF)
CSP O&M costs were analysed in terms of:
 Fixed Operating and Maintenance Costs (FOM);
 Variable Operating and Maintenance Costs (VOM); and
 Total Operating Expenditures (OPEX).
In order to arrive at comparable results between technologies, BREE and WorleyParsons
estimated the O&M costs based on:
 Reference Plants with similar Solar Plant characteristics: localisation, net capacity,
capacity factor, hours of Thermal Energy Storage (TES) and type of cooling system(s);
and
 Cost estimate amounts that were updated to 2012 USD.
When information was not available, necessary estimates were made using WorleyParsons’
in-house data and based on global market trends observed in various publications.
4.6.2 Review of the evidence
The following international organisations were consulted to provide the AETA 2013 O&M
costs update for the selected CSP technologies:
 International Renewable Energy Agency (IRENA) (www.irena..org);
 International Energy Agency (IEA) (www.iea.org);
 European Solar Thermal Electricity Association (ESTELA) (www.estelar.de);
 The World Bank (WB) (www.worldbank.org);
 National Renewable Energy Laboratory (NREL) (www.nrel.gov);
 Protermosolar (www.protermosolar.es);
 Institute for Energy Diversification and Saving (IDEA) (www.idea.es);
 Renovetec (www.renovetec.es); and
 CSP Today (www.csptoday.com)
The approach in reviewing O&M costs for the 2013 update for CSP technology was only to
use new sources of information published since the AETA 2012 report was written. This was
43
maintained for all but the learning rates estimation which is due to the lack of any new
updated information published since 2012 in relation to this.
Upon review of the available public domain information, it was found that IEA, ESTELA,
WB, Protermosolar, Renovetec and IDEA do not have any new relevant public information
related to CSP O&M costs. However, IRENA 2013b, IRENA 2013c, and NREL 2012 are
new references from IRENA and NREL that are considered relevant, and which were used in
this report.
The information contained in these references did not provide updated costs for all of the
CSP technologies being considered in this Report, and the values offered were not provided
in terms of FOM and VOM costs, as preferred.
Due to the lack of new relevant information in the public domain, the AETA 2013 Model
Update process obtained reports from CSP Today, a private international organisation
focused on news, events, reports, updates and information for the CSP industry in markets
such as India, South Africa, Spain, USA, Chile and MENA regions. The Update acquired the
last edition of PT and ST reports CSP Today 2012a, and CSP Today 2012b, for which OPEX
costs were analysed.
4.6.3 AET A 2012 O&M CSP costs report comparison
Operating and Maintenance expenses were provided in terms of fixed and variable costs in
the AETA 2012 report and this Model Update has modified these for 2013 for PT, ST and LF
technologies, based on the references cited above and further consideration of learning rates
for the CSP industry.
Most CSP projects with commercial operational experience are parabolic trough technology,
as it is the most mature technology and currently more is reported and known about actual
costs than other CSP technologies. Nevada Solar One, as an example, is a 64MWe parabolic
trough plant based in California which was commissioned in 2007 and it is the first plant
built after the SEGS development during the 1980-90s, also in California.
Andasol 1, the 50 MWe parabolic trough plant based in Spain, is also the first CSP plant
worldwide to implement a commercial thermal energy storage system with a capacity of 7.5
hours of full load storage. It commenced operation at the end of 2008 and other similar and
larger trough projects are now operating or being constructed.
As the most mature CSP technology, trough plant should be further down the operational and
design operability maturity path and hence have a lower opportunity for O&M cost
reductions through learning. By contrast, Solar Tower and Linear Fresnel systems are only
beginning to be deployed at larger scale and, hence, there is expected to be more potential to
reduce their capital and operating costs and improve performance.
Learning rates have been argued by stakeholders as being very significant for CSP plant, with
comments of the AETA 2012 report centring on this issue. Disappointingly, there is no new
published evidence or actual plant report data that could be found by the AETA stakeholders
and WorleyParsons to add to that used for the 2012 report. There is, however, new evidence
on the reduction in LCOE for CSP technologies, and WorleyParsons linked OPEX
contribution to these LCOE predictions so that a sense of future reductions could be made.
This is outlined further in the following Sections.
44
4.6.3.1 A S S U M P T I O N S A N D C O N S I D E R A T I O N S
FOM and VOM Breakdown
The following costs are included in proceeding FOM cost estimates for CSP technologies as
an annual cost per MW capacity:
 Insurance;
 Labour costs; and
 Fixed service maintenance contracts.
Similarly, the following costs are included in the VOM cost estimates as a cost rate per MWh
of sent out energy:
 Material and maintenance costs: spare parts, equipment maintenance and unscheduled
inspections; and
 Utilities costs: water, auxiliary fuel and auxiliary power, when applicable.
Some items, such as spare parts for scheduled maintenance, could be considered FOM costs.
However, to simplify the comparison and to homogenise all of the analyses across
technologies, all concepts related to plant material and maintenance were included in the
VOM costs.
4.6.3.2 AET A 2012 O&M CSP C O S T S C O M P A R I S O N R E P O R T
The technical characteristics of the reference CSP Plants used in the AETA 2012 report have
been extracted from the AETA Model Version 1_0 (BREE 2012) and are summarised in
Table 12.
Table 12: AETA 2012 Reference Plant Technical Characteristics
Plant
Units
Characteristics
Parabolic
Parabolic
Solar
Solar
Linear
Linear
Trough
Trough
Tower
Tower
Fresnel
Fresnel
without
with
without
with
without
with
Storage
Storage
Storage
Storage
Storage
Storage
Plant Net Capacity
MW
138
135
122
18
230
225
Location
N/A
Unknown
Unknown
Unknown
Unknown
Unknown
Unknown
Isolation
kWh/m2/year
Unknown
Unknown
Unknown
Unknown
Unknown
Unknown
Hours of TES
h
-
7
-
6
-
6
Capacity Factor
per cent
23
42
31
42
23
42
Type of Cooling
N/A
Unknown
Unknown
Unknown
Unknown
Unknown
Unknown
FOM
$/MW/year
60,000
65,000
70,000
60,000
65,000
65,000
VOM
$/MWh sent out
15
20
15
15
15
20
Based on the information above, this Model Update estimated the following parameters for
the CSP technologies evaluated in this study:
45
 Total net energy production in terms of MWh delivered per year;
 FOM and VOM in terms of USD per year; and
 Total OPEX costs in terms of USD per year and USD per total net energy production
per year.
The results are listed in Table 13 below.
Table 13: AETA 2012 O&M Opex costs on a per kWh basis
Plant
Units
Characteristics
Parabolic
Parabolic
Solar
Solar
Linear
Linear
Trough
Trough
Tower
Tower
Fresnel
Fresnel
without
with
without
with
without
with
Storage
Storage
Storage
Storage
Storage
Storage
138
135
122
18
230
225
Plant Net Capacity
MW
Net Energy sent out
MWh/year
278,042.4
496,692
331,303.2
66,225.6
463,404
827,820
FOM
$/year
8,280,000
8,775,000
8,540,000
1,080,000
14,950,000
14,625,000
VOM
$/year
4,170,636
9,933,840
4,969,548
993,384
6,951,060
16,556,400
OPEX
$/year
12,450,636
18,708,840
13,509,548
2,073,384
21,901,060
31,181,400
OPEX
$/kWh
0.0448
0.0377
0.0408
0.0313
0.0473
0.0377
FOM
per cent
66.50
46.90
63.21
52.09
68.26
46.90
VOM
per cent
33.50
53.10
36.79
47.91
31.74
53.10
The percentages of FOM and VOM costs as part of the total OPEX costs are presented in
Figure 5.
Figure 5: AETA 2012 FOM and VOM Percentages of Total OPEX Costs
46
In Figure 5, FOM costs are, in general terms, significantly higher than VOM costs because
they include the higher cost items, such as insurance, labour costs and fixed service contracts.
However, as shown in the Figure, VOM costs are higher or approximately equal to FOM
costs for technologies with energy storage given the criteria selected for the breakdown
between FOM costs and VOM costs. FOM costs will remain relatively consistent from yearto-year, while VOM costs should be broken down even further since the costs of water,
natural gas (if required) and electricity vary between locations and from one year to another.
Total OPEX costs are expressed in terms of USD per total net energy production per year and
are between 0.0313 and 0.0473 USD/kWh, as listed in Table 13. These values are aligned
with the values provided by international institutions cited, although they appear to be
somewhat inflated in comparison with those values that are closer to 0.025 and 0.035
USD/kWh as published by others (e.g., IRENA).
4.6.3.3 AET A 2013 O&M C O S T S U P D A T E
Similar Plant characteristics to AETA 2012 were considered for the appropriate comparison
of O&M costs for this update. Plant characteristics include: location, net capacity, capacity
factor, hours of TES and type of cooling. For this Report, the characteristics of the reference
plants used are described in Table 14.
Table 14: PT and ST Reference Plant Characteristics
Plant
Units
characteristics
Parabolic
Parabolic
Solar Tower
Solar Tower
Trough without
Trough with
without
with Storage
Storage
Storage
Storage
Plant Net Capacity
MW
100
100
100
100
Location
N/A
MENA region
MENA region
MENA region
MENA region
Isolation
kWh/m2/year
2400
2400
2400
2400
Hours of TES
h
0
6
0
6
Capacity Factor
per cent
26
46
27.5
47.6
Type of Cooling
N/A
Dry
Dry
Dry
Dry
Source
N/A
WorleyParsons
CSP Today, 2012a
WorleyParsons
CSP Today, 2012b
The 2013 O&M costs were estimated using as a basis the information provided in the CSP
2012 reports (CSP 2012a and 2012 b). The following considerations were taken into account:
 the CSP Today reports only consider PT and ST plants with thermal storage.
WorleyParsons made the following estimates based on experience with solar and
conventional power plants based on PT and ST technologies without TES;
 estimated the capacity factor based on plant capacity, location and type of cooling
 adjusted the insurance, material and maintenance, and labour costs based on the
solar field reduction factor, when applicable
 adjusted the steam turbine maintenance based on the potential hours of operation
47
 adjusted the plant electricity and water consumption based on the total net
production
 assumed similar auxiliary fuel consumption for the plant with and without TES. This
assumption is due to the reference plants being based in the same location, thus
requiring similar auxiliary fuel consumption for start-up. Minimal differences in
auxiliary fuel consumption for freeze protection due to increased time offline for a
plant without TES system, compared to a plant with TES, are expected but not
considered in this Report as the impact would be minor
 the capacity factor provided by CSP Today for PT, with thermal storage, is considered
high. Based on the plant location and capacity, WorleyParsons would anticipate the
capacity factor to be closer to 42 per cent instead of 46 per cent, as indicated in Table
14 above. This difference in capacity factor directly impacts the estimated VOM cost,
which is correlated with plant production. For comparison purposes, the value provided
by CSP Today has maintained; and
 with respect to Linear Fresnel technology, updated information has not been published
since the AETA 2012 report release by the references listed in Section 4.6.2, which
WorleyParsons consulted. For the purpose of updating the estimates to 2013, it was
assumed that the evolution of the O&M costs would be similar to that of parabolic
trough plants and the same escalation factors were applied.
The resulting 2013 and 2012 O&M costs are listed in Table 15 below for comparison:
Table 15: 2013 CSP O&M Costs Compared to 2012 O&M Costs
CSP Technology
O&M Costs
Parabolic Trough
FOM
$/MW/year
VOM
$/MWh sent out
OPEX
without Storage
Parabolic Trough with
Storage
Solar Tower without
Storage
Solar Tower with
Storage
Linear Fresnel without
Storage
AETA 2012
WorleyParsons 2013 update
60,000
59,176
15.00
15.19
$/kWh
0.0448
0.0412
FOM
$/MW/year
65,000
72,381
VOM
$/MWh sent out
20.00
11.39
OPEX
$/kWh
0.0377
0.0293
FOM
$/MW/year
70,000
58,285
VOM
$/MWh sent out
15.00
7.07
OPEX
$/kWh
0.0408
0.0313
FOM
$/MW/year
60,000
71,372
VOM
$/MWh sent out
15.00
5.65
OPEX
$/kWh
0.0313
0.0228
FOM
$/MW/year
65,000
64,107
VOM
$/MWh sent out
15.00
15.19
OPEX
$/kWh
0.0473
0.0434
48
CSP Technology
O&M Costs
Linear Fresnel with
FOM
$/MW/year
VOM
$/MWh sent out
OPEX
$/kWh
Storage
AETA 2012
WorleyParsons 2013 update
65,000
72,381
20.00
11.39
0.0377
0.0293
The total OPEX costs per year from the AETA 2012 report and the WorleyParsons’ estimates
that were updated for 2013 are compared in Figure 6 below:
Figure 6: Comparison of OPEX Costs per Total Annual Plant Production per Year: AETA 2012
Report and 2013 Update
Reductions of approximately 20 - 27 per cent in O&M costs would be realised by CSP with
TES according to the updated 2013 WorleyParsons estimates, compared to the same costs
reported in the AETA 2012 report. However, reductions for PT and LF without TES were
found to be lower at approximately 8 per cent.
The IRENA reports (IRENA 2013b, IRENA 2013c) provide values for OPEX between 0.025
and 0.035 USD/kWh for PT and ST technologies with and without TES. Values updated to
2013 by WorleyParsons are between 0.023 and 0.0412 USD/kWh for PT and ST
technologies, which align with the IRENA values. However, IRENA does not differentiate
between the utilisation of TES. Solar technologies without TES have fewer hours of
production, and although OPEX costs are lower in terms of USD/MW compared with solar
technologies with TES, OPEX costs in terms of costs per total annual plant production per
year will typically be higher for technologies that do not use TES.
4.6.3.4 O&M CSP L E A R N I N G R AT E S
Cost reductions on CSP technologies are expected to come from the following main actions:
 economies of scale in the plant size and manufacturing industry;
 learning impacts on design, construction and operation phases;
49
 advances in R&D of the following factors;
 Components: Solar receivers, mirrors, HTF, storage media, supporting structures,
trackers and auxiliary systems
 Systems: Direct steam generation, storage systems or hybrid cooling systems
 Configurations: Hybridisation or duel electricity water plants
 a more competitive supply chain;
 improvements in the performance of the solar field, solar-to-electric efficiency and
thermal energy storage systems;
 increases in the life of plants; and
 reduced financial costs.
Based on the parameters listed above, the LCOE from Solar Thermal technologies is likely to
be continuously decreasing and this is born out in the literature that has been reviewed. Based
on the IRENA 2013b report, the evolution of the LCOE from trough and power tower CSP
technologies shows how the LCOE is decreasing as technology development increases in
Table 16 below. Estimates for LCOE for the hypothetical trough and tower CSP plants in
2014 are also included.
50
Table 16: Estimated LCOE form Existing and Hypothetical Trough and Solar Tower CSP
Technologies
CSP
Year
Technology
Trough
Capacity
Plant Name
Location
(MW)
DNI
LCOE 2012
(kWh/m2/year)
$/kWh Installed
1981
0.5
PSA
Spain
2000
0.64
1983
13.8
SEGS I
California
2700
0.39
1989
30
SEGS II – VIII
California
2700
0.26
1992
80
SEGS VIII & IX
California
2700
0.20
2008 - 2009
50
Andasol 1, 2
Spain
2000
0.35
2010
50
Solnova 1 & 3
Spain
2000
0.34
2010 - 2011
50
Extresol 1 & 2
Spain
2014
250
Unspecified (wet
Not provided
2000
0.35
Not provided
0.20
cooling, no storage)
1987
10
Solar One
California
2700
0.58
2007
11
PS10
Spain
2000
0.34
2009
20
PS20
Spain
2000
0.36
2011
19.9
Gemasolar (wet
Spain
2000
0.33
Not provided
0.15
cooling, 15hr
Tower
storage)
2014
120
Unspecified
Not Provided
(dry cooling,
storage)
International Institutions, such as IRENA, ESTELA or the World Bank, agree that the LCOE
and capital cost reductions of 28 per cent to 60 per cent are envisioned by 2020 – 2025 for
such plant. Estimates of possible LCOE reductions for CSP technology from 2012 to 2025
are provided in Figure 7, taken from Kearny (2010).
51
Figure 7: Expected LCOE Reductions for CSP Technology from 2012 to 2025
Source: (Kearny, 2010)
The O&M maintenance costs of modern CSP Plants are lower than those for Californian
SEGS Plants built in the 1980s and 1990s, which has a total combined capacity of 354 MW
and estimated O&M costs of USD 0.04/kWh (IRENA 2013b). However, CSP experienced no
growth from early 1990s until the mid-2000s, as can be seen in Table 16 above.
As stated at the beginning of Section 4.6.2, Andasol 1 was the first 50 MWe parabolic trough
plant built after SEGS which included a thermal energy storage system. It commenced
operation at the end of 2008. Podewils (2008) estimated Andasol 1 O&M costs of EUR
0.072/kWh, or USD 0.095/kWh (considering 2012 medium rate exchange EUR/USD of
0.7553). This value is high compared to OPEX estimations for PT with TES provided by
both this 2013 update and the AETA 2012 report (0.0293 and 0.0377 USD/kWh
respectively). Therefore, according to the information detailed above, considerable learning
improvements to O&M costs have been already achieved from the commencement of
operation of Andasol 1 to the time of this Report.
`WorleyParsons’ estimations on the LCOE of parabolic trough plants is in the range of
USD 0.20/kWh to USD 0.35/kWh and that of solar towers between USD 0.17/kWh and
USD 0.29/kWh. However, in areas with excellent solar resources, the range could be as low
as USD 0.14/kWh to USD 0.18/kWh.
The following considerations have been taken into account for O&M cost learning rates
forecast:
 WorleyParsons LCOE estimations as set out above;
 Potential average envisaged LCOE reductions of 47.5 per cent by 2025 based on Figure
7 above;
 OPEX contribution on LCOE of 20 per cent; and
52
 assuming that all components involved in the LCOE (CAPEX, OPEX and financial
expenses) reduce at the same rate so percentage contributions remain constant.
According to these considerations, WorleyParsons estimates that OPEX values by 2025 could
reach from 0.021 to 0.037 USD/kWh for PT technology and from 0.018 to 0.031 USD/kWh
for ST technology.
Technological improvements have reduced the requirement of replacing mirrors and
receivers. Automation has reduced the cost of other O&M procedures by as much 30 per
cent. As a result of O&M procedure improvements (both cost and plant performance), the
total O&M costs of CSP plants in the long-term are likely to be below USD 0.025/kWh
(IRENA 2013b).
Parabolic trough system in the United States would have O&M costs of around USD 0.02 to
USD 0.03/kWh, meanwhile the O&M costs of parabolic trough and solar tower power plants
currently under construction in South Africa have estimated O&M costs of between USD
0.029 and USD 0.036/kWh (also IRENA 2013b).
WorleyParsons estimations are in alignment with IRENA estimations in terms of current and
envisaged CSP OPEX costs.
4.6.3.5 C O N C L U S I O N S – CSP
The following main conclusions were made based on this study in relation to CSP
technologies:
 the 2013 WorleyParsons CSP O&M costs update resulted in values between 0.023 and
0.043 USD/kWh based on 2012 USD;
 reductions in CSP O&M costs between 8 per cent and 27 per cent were obtained in
comparison to values provide in AETA 2012 report;
 the total O&M costs of CSP Plants in the long-term are likely to be below USD
0.025/kWh;
 the updated values for 2013 by WorleyParsons are in alignment with the values
provided by recognised international institutions; and
 at the time of this report, the only CSP technology with substantial operation capacity
was PT. Only three utility-scale ST plants were in operation at the time of this report
(PS-10, PS-20 and Gemasolar), of which only one (Gemasolar) uses TES. Though
several process steam and small-scale LFR Plants are currently in operation, only one
utility-scale LFR (Puerto Erradio 2) was in operation at the time of this report.
4.7 AETA 2013 O&M Learning Rate recommendation
The learning rate used in AETA 2012 for O&M is applied to all technologies assessed and
includes fossil fuel technologies and emerging technologies. The learning rate is set at an
improvement of 0.2 per cent per annum.
In addition to the improvement rate, O&M is escalated at a rate of 150 per cent of CPI per
year, based on experience, with increases in parts and labour costs.
The CPI rate set in the model is 2.5 per cent per annum.
53
O&M cost information in the public domain, in both quantum and quality, is poor for
contemporary data. Information supporting O&M learning rates is equally poor. There are
indications that emerging technologies do have the potential for increased O&M learning
rates relative to mature technologies.
For the renewable energy technologies studied in this report onshore wind is considered
mature and it is recommended that the AETA 2012 report value of 0.2 per cent is maintained.
For all other renewable energy technologies studied in this report a more aggressive learning
rate of 2.5 per cent is recommended. This will effectively cancel out the CPI escalation
adjustment and provide a “flat line” O&M rate for future years. This will provide a value in
line with the learning rate conclusions for PV.
The learning rate for CSP is considered to have greater potential for reduction but due to the
high level of analysis in this report (and therefore uncertainty) it is proposed that a maximum
of two learning rates is appropriate for the AETA model.
Table 17: AETA Learning Rate Comparison
AETA 2012 Learning Rate
AETA 2013 update Learning Rate
Onshore Wind
0.2 per cent
0.2 per cent
Offshore Wind
0.2 per cent
2.5 per cent
PV – all technologies
CSP – all technologies
54
5
CHANGES TO THE LCOE
Changes to the model parameters described in the earlier sections have resulted in changes to
the LCOE estimates for a number of technologies. The LCOE estimate values for all
technologies and associated range of uncertainty are shown in the Figures 8 to 13 below.
Note that the values listed are for a base value carbon price modifier of zero per cent, which
places no value on carbon emissions.
For selected technologies where there are significant cost differences, Figure 14 provides a
comparison of mid-range LCOE values for the AETA 2013 and AETA 2012 Models. Key
features of the Figures 8 to 14 are as follows:

both in AETA 2012 and 2013 Model update, LCOE costs are provided for the years
2012, 2020, 2025, 2030, 2040, and 2050;

cost ranges are provided for each technology that accounts for differences in fuel prices,
and state-based variations;

LCOE costs vary substantially across the technologies from $89/MWh (combined cycle
gas turbine) to $351/MWh (solar thermal linear fresnel) in 2012, and $73/MWh (PV
non-tracking) to $247/MWh (IGCC black coal CCS) in 2050;

the inter-technology LCOE comparisons figures (Figures 8 to 13) reveal changes in
relative costs of technologies over time. Key results include: renewable technologies
have higher LCOEs than the lowest cost non-renewable technologies, and the relative
LCOE rankings significantly change post 2030. The LCOE of solar PV become lower
than the non-renewables, from mid 2030 onwards; and

large changes in LCOE results between AETA 2013 Update and AETA 2012 are
depicted in Figures14 below. Figure 14 compares LCOEs at 2050 between the AETA
2013 Update and AETA 2012 for a selected number of technologies that have changed
significantly, for NSW (AETA developed LCOEs by each Australian state). Differences
in technology LCOEs are explained by a multiplicity of factors including the technical
developments, O&M costs and learning rate changes.
55
Figure 8: Updated LCOEs for AETA 2013 Model technologies, values for 2012 (NSW), with carbon price set to zero
LCOE FOR 2012 TECHNOLOGIES (NSW*)
* Note: Default region is NSW except bown coal
technologies (VIC) and SWIS scale (as specified)
500
450
400
LCOE ($/MWh)
350
LCOE includes, where relevant, allowance for:
- Carbon Price
- CO2 transport and sequestration cost
- Plant capital cost (EPC basis) within battery limits
- Owners costs excluding interest during construction
- Fixed and variable operating costs
- Fuel costs
- Economic escalation factors
300
250
200
150
100
50
0
56
Figure 9: Updated LCOEs for AETA 2013 Model technologies, values for 2020 (NSW), with carbon price set to zero.
LCOE FOR 2020 TECHNOLOGIES (NSW*)
* Note: Default region is NSW except bown coal
technologies (VIC) and SWIS scale (as specified)
450
400
350
LCOE ($/MWh)
300
LCOE includes, where relevant, allowance for:
- Carbon Price
- CO2 transport and sequestration cost
- Plant capital cost (EPC basis) within battery limits
- Owners costs excluding interest during construction
- Fixed and variable operating costs
- Fuel costs
- Economic escalation factors
250
200
150
100
50
0
57
Figure 10: Updated LCOEs for AETA 2013 Model technologies, values for 2025 (NSW), with carbon price set to zero.
LCOE FOR 2025 TECHNOLOGIES (NSW*)
* Note: Default region is NSW except bown coal
technologies (VIC) and SWIS scale (as specified)
400
350
LCOE ($/MWh)
300
LCOE includes, where relevant, allowance for:
- Carbon Price
- CO2 transport and sequestration cost
- Plant capital cost (EPC basis) within battery limits
- Owners costs excluding interest during construction
- Fixed and variable operating costs
- Fuel costs
- Economic escalation factors
250
200
150
100
50
0
58
Figure 11: Updated LCOEs for AETA 2013 Model technologies, values for 2030 (NSW), with carbon price set to zero.
LCOE FOR 2030 TECHNOLOGIES (NSW*)
* Note: Default region is NSW except bown coal
technologies (VIC) and SWIS scale (as specified)
400
350
LCOE ($/MWh)
300
LCOE includes, where relevant, allowance for:
- Carbon Price
- CO2 transport and sequestration cost
- Plant capital cost (EPC basis) within battery limits
- Owners costs excluding interest during construction
- Fixed and variable operating costs
- Fuel costs
- Economic escalation factors
250
200
150
100
50
0
59
Figure 12: Updated LCOEs for AETA 2013 Model technologies, values for 2040 (NSW), with carbon price set to zero.
LCOE FOR 2040 TECHNOLOGIES (NSW*)
* Note: Default region is NSW except bown coal
technologies (VIC) and SWIS scale (as specified)
400
350
LCOE ($/MWh)
300
LCOE includes, where relevant, allowance for:
- Carbon Price
- CO2 transport and sequestration cost
- Plant capital cost (EPC basis) within battery limits
- Owners costs excluding interest during construction
- Fixed and variable operating costs
- Fuel costs
- Economic escalation factors
250
200
150
100
50
0
60
Figure 13: Updated LCOEs for AETA 2013 Model technologies, values for 2050 (NSW), with carbon price set to zero
LCOE FOR 2050 TECHNOLOGIES (NSW*)
* Note: Default region is NSW except bown coal
technologies (VIC) and SWIS scale (as specified)
400
350
LCOE ($/MWh)
300
LCOE includes, where relevant, allowance for:
- Carbon Price
- CO2 transport and sequestration cost
- Plant capital cost (EPC basis) within battery limits
- Owners costs excluding interest during construction
- Fixed and variable operating costs
- Fuel costs
- Economic escalation factors
250
200
150
100
50
0
.
61
Figure 14: Comparison of AETA 2013 Model and AETA 2012 Model LCOE estimates, selected technologies, 2050
250
200
150
100
50
AETA 2012
AETA 2013
0
62
5.1 Conclusions
The Australian Energy Technology Assessment (AETA 2012) provided the best available and most up-todate cost estimates for 40 electricity generation technologies under Australian conditions. To ensure that
the cost estimates for the various technologies are consistent, all common input costs (e.g. labour,
materials, components, carbon price) were itemised. To ensure that the AETA costings remain up to date,
AETA costs are reviewed in this AETA 2013 Model Update report.
The AETA 2013 refresh was developed in close consultation with a stakeholder reference group drawn
from industry and research/academic organisations with interests and expertise in a diverse range of
electricity generation technologies.
The AETA 2013 Model results reflect the change to exclude the value of a carbon price in the Levelised
Cost of Energy (LCOE). All technologies have experienced a minor reduction in LCOE relative to 2012
(offset in some cases by other factors) due to the change to an amortisation period of 30 years plus the
construction period.
Comparing the 2012 AETA results without a carbon price to the 2013 results without a carbon price, there
are significant reductions in the LCOE of solar technologies and onshore wind. This is as a consequence of
changes to the fixed and variable Operations and Maintenance (O&M) costs for these technologies. For the
solar technologies, the adjustment of the capital learning rate to 2.5 per cent has also contributed to the
LCOE reduction. Offshore wind also has an increased learning rate, but this has been offset to a large extent
by increased variable O&M costs.
Nuclear LCOE has increased significantly due to higher estimates for capital costs.
Efficiency for coal fired plants with CCS retrofits has been revised downwards to better reflect the expected
efficiency of these plants and has the effect of increasing the LCOE.
63
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January. http://www.irena.org/DocumentDownloads/Publications/IRENA-ETSAPper
cent20Techper cent 20Briefper cent20E11per cent20Solarper cent20PV.pdf
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See www.nrel.gov
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Appendix A
Electricity Generation Technologies in AETA 2012 Report and Model
The 40 AETA electricity generation technologies are:
1. Integrated Gasification and Combined Cycle (IGCC) plant based on brown coal
2. IGCC plant with Carbon Capture and Sequestration (CCS) based on brown coal
3. IGCC plant based on bituminous coal
4. IGCC plant with CCS based on bituminous coal
5. Direct injection coal engine (clean lignite, e.g. brown coal technology)
6.
Pulverised coal supercritical plant based on brown coal
7. Pulverised coal supercritical plant with post combustion CCS based on brown coal
8. Pulverised coal subcritical plant with post combustion CCS based on brown coal (retrofit)
9. Pulverised coal supercritical plant based on bituminous coal
10. Pulverised coal supercritical plant based on bituminous coal - SWIS relevant scale
11. Pulverised coal supercritical plant with CCS based on bituminous coal
12. Pulverised coal subcritical plant with post combustion CCS based on bituminous coal (retrofit)
13. Adding CCS to existing Combined Cycle Gas Turbine (CCGT) power plants (retrofitting)
14. Oxy combustion pulverised coal supercritical plant based on bituminous coal
15. Oxy combustion pulverised coal supercritical plant with CCS based on bituminous coal
16. Combined cycle plant burning natural gas
17. Combined cycle plant burning natural gas - SWIS relevant scale
18. Combined cycle plant with post combustion CCS
19. Open cycle plant burning natural gas
20. Solar thermal plant using compact linear fresnal reflector technology w/o storage
21. Solar thermal plant using parabolic trough technology w/o storage
22. Solar thermal plant using parabolic trough technology with storage
23. Solar thermal plant using compact linear fresnal reflector technology with storage
24. Solar thermal plant using central receiver technology w/o storage
25. Solar thermal plant using central receiver technology with storage
26. Solar photovoltaic (PV) - non-tracking
27. Solar photovoltaic (PV) - single axis tracking
28. Solar photovoltaic (PV) - dual axis tracking
29. Wind (on-shore)
30. Wind (off-shore)
31. Wave/Ocean
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32. Geothermal - hot sedimentary aquifer (HSA)
33. Geothermal - enhances geothermal system (EGS)
34. Landfill gas power plant
35. Sugar cane waste power plant
36. Other biomass waste power plant (e.g. wood)
37. Nuclear; Gen 3+
38. Nuclear; Small Modular Reactors (SMR)
39. Solar/coal hybrid
40.
Integrated solar combined cycle (ISCS) – parabolic trough with combined cycle gas.
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Appendix B
Consultations with Stakeholders
This study has been undertaken in close consultation with a Stakeholder Reference Group drawn from
Australian industry and domestic as well as overseas research/academic organisations with interests and
expertise in a diverse range of electricity generation technologies. These stakeholders were invited to
provide evidence of the latest estimates for the costs and performance of various technologies.
In addition, the AETA project also had a Project Steering Committee comprising staff from BREE,
AEMO, CSIRO and other independent experts to provide technical advice and support. The following
agencies participated in the stakeholder reference group meetings or were forwarded the documents
presented at the meetings.
AETA Stakeholder Reference Group
Australian Coal Association
Australian Energy Market Operator
Australian Geothermal Energy Association
Australian National Low Emissions Coal R&D
Australian National University
Australian Renewable Energy Agency
Australian Solar Thermal Energy Association
Australian Sugar Milling Council
Australian Treasury
Bureau of Resources and Energy Economics
Clean Energy Council
CSIRO
Department of Industry
Economic Research Institute for ASEAN and East Asia
Energy Retailers Association of Australia
Energy Users Association of Australia
Evans and Peck
Ferrostaal
Global CCS Institute
Grid Australia
Intergen
International Energy Agency, France
International Power Suez
IRENA Innovation and Technology Centre, Germany
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National Generators Forum
Oceanlinx Limited
Origin Energy
Private Generators Group
The Institute of Energy Economics, Japan
The Energy Research Institute, New Delhi
University of Melbourne Energy Institute
University of Queensland Energy Initiative
UQ Energy Economics & Management Group
Wyldgroup
WorleyParsons
Two AETA Stakeholders Reference Group meetings took place on 30 April 2013 and 17 July 2013. In
addition, the AETA Project Steering Committee met on 24 June 2013.
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BREE contacts
Executive Director, BREE
Bruce Wilson
bruce.wilson@ret.gov.au
(02) 6243 7901
Deputy Executive Director
Wayne Calder
wayne.calder@bree.gov.au
(02) 6243 7718
Modelling & Policy Integration Arif Syed
Program Leader
arif.syed@bree.gov.au
(02) 6243 7504
Data Statistics
Program Leader
geoff.armitage@bree.gov.au
(02) 6243 7510
Geoff Armitage
Energy and Quantitative Analysis Allison Ball
Program Leader
allison.ball@bree.gov.au
(02) 6243 7539
Resources – Program Leader
john.barber@bree.gov.au
(02) 6243 7988
John Barber
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