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Renewable Energy Opportunities for the Decentralised Energy Master Plan - Renewable Energy

A Financial and Economic Analysis

April 2013

Report to the City of Sydney

The Allen Consulting Group ii

Allen Consulting Group Pty Ltd

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Suggested citation for this report:

Allen Consulting Group, 2013, “Renewable Energy Opportunities for the Decentralised Energy Master Plan – Renewable Energy: A Financial and Economic Analysis” Report to the City of Sydney, Sydney, April.

Disclaimer:

While the Allen Consulting Group endeavours to provide reliable analysis and believes the material it presents is accurate, it will not be liable for any claim by any party acting on such information.

© Allen Consulting Group 2013

The Allen Consulting Group iii

Disclaimer

Inherent Limitations

This report on renewable energy opportunities for the City of Sydney‘s

Decentralised Energy Master Plan – Renewable Energy is given subject to the

written terms of the Allen Consulting Group‘s engagement. The services provided

in connection with this engagement comprise an advisory engagement which is not

subject to Australian Auditing Standards or Australian Standards on Review, or

Assurance Engagements, and consequently no opinions or conclusions intended to

convey assurance have been expressed.

No warranty of completeness, accuracy or reliability is given in relation to the

statements and representations made by, and the information and documentation

provided by, the City of Sydney representatives consulted as part of the process.

The Allen Consulting Group has indicated within this report the sources of the

information provided. We have not sought to independently verify those sources

unless otherwise noted within the presentation.

Any economic projections or forecasts in this report rely on economic inputs that

are subject to unavoidable statistical variation. They also rely on economic

parameters that are subject to unavoidable statistical variation.

While all care has been taken to ensure that statistical variation is kept to a

minimum, care should be taken whenever using this information. Any estimates or

projections will only take into account information available to the Allen

Consulting Group up to the date of the deliverable and so findings may be affected

by new information. Events may have occurred since we prepared this report which

may impact on it and its findings.

The Allen Consulting Group is under no obligation in any circumstance to update

this report, in either oral or written form, for events occurring after the report has

been issued in final form.

Third Party Reliance

This presentation has been prepared at the request of the City of Sydney in

accordance with the contracted terms of the Allen Consulting Group‘s engagement.

Other than our responsibility to the City of Sydney, neither the Allen Consulting

Group nor any member or employee of the Allen Consulting Group undertakes

responsibility arising in any way from reliance placed by a third party on this

report. Any reliance placed is that party‘s sole responsibility.

The Allen Consulting Group accepts no responsibility to anyone other than the City

of Sydney for the information contained in this report.

The Allen Consulting Group iv

Contents

Executive summary viii

Introduction viii

Main summary points x

Conclusions and recommendations xiii

Section 1 Overview 1

Scope of report 1

Green Infrastructure 2

The Decentralised Energy Master Plan – Renewable Energy 3

Electricity generation technologies 4

Renewable gas resources 6

Limitations of this report 6

Section 2 Our approach 8

Scenarios 8

Financial analysis 10

Economic analysis 12

Assumptions 16

Section 3 Financial analysis 18

Capital expenditures 19

Operating expenditures 19

Delivered Cost 21

Conditional viability 22

Financial analysis - summary and conclusion 27

Section 4 Economic analysis 28

Potential greenhouse gas abatement 28

Marginal social cost of abatement 29

Economic analysis – summary and conclusion 40

The Allen Consulting Group v

Section 5 Trigeneration with renewable gas feedstock 41

Renewable gas 41

Methodology 45

Gas availability 46

Gas capital costs 51

Cost of gas 52

Delivered cost of electricity 54

Marginal social cost of abatement 55

Evaluation of renewable electricity options 58

Section 6 Conclusion 60

Appendix A Economic assumptions 63

Overview 63

Macroeconomic assumptions 63

Policy framework assumptions 66

Appendix B Cost assumptions 69

Overview 69

Cost assumptions 69

Appendix C Electricity technology assumptions 71

Overview 71

Technical specifications 71

Appendix D Renewable gas resources assumptions 73

Overview 73

Detailed SNG data 74

Levelised Cost of Gas 78

Gas cost assumptions 78

Financial assumptions 81

Delivery cost assumptions 82

References 87

R E N E W A B L E E N E R G Y O P P O R T U N I T I E S

The Allen Consulting Group vi

Abbreviations and acronyms

ACG Allen Consulting Group

AD anaerobic digestion

AEMO Australian Energy Market Operator

AETA Australian Energy Technology Asessments

ALPF Australia‘s Low Pollution Future: The Economics of Climate

Change

BREE Bureau of Resources and Energy Economics

C&I commercial and industrial

CCGT combined cycle gas turbine

CCS carbon capture and storage

CFI carbon farming initiative

CO2 carbon dioxide

CO2-e carbon dioxide equivalent

CPM carbon pricing mechanism

CPRS Carbon Pollution Reduction Scheme

DCCEE Department of Climate Change and Energy Efficiency

ERA Extended Regulatory Area

ETS emissions trading scheme

EU European Union

GDP gross domestic product

GJ gigajoule

HHV higher heating value

IGU International Gas Union

IPART Independent Pricing and Regulatory Tribunal

kgCO2-e kilograms of carbon dioxide equivalents

kW kilowatt

kWh kilowatt hour


The Allen Consulting Group vii

LCOE levelised cost of energy

LCOG levelised cost of gas

LGA local government area

LGC Large-scale Generation Certificate

LNG liquefied natural gas

LRET Large-scale Renewable Energy Target

MAC marginal abatement cost

MRET Mandatory Renewable Energy Target

MSW municipal solid waste

MT megatonne

MtCO2-e megatonnes of carbon dioxide equivalents

MW megawatt

MWh megawatt hour

NTNDP National Transmission Network Development Plan

O&M operating and maintenance

PJ petajoule

PV photovoltaic

REC Renewable Energy Certificate

RET Renewable Energy Target

SGLP Strong Growth, Low Pollution: Modelling a Carbon Price

SMA Sydney Metropolitan Area

SNG substitute natural gas

SRES Small-scale Renewable Energy Scheme

STC Small-scale Technology Certificate

T&D transmission and distribution

tCO2-e tonnes of carbon dioxide equivalents

TW terawatt

TWh terawatt hour

WACC weighted average cost of capital


The Allen Consulting Group viii

Executive summary

Introduction

The City of Sydney has engaged the Allen Consulting Group to conduct a financial

and economic analysis of renewable energy opportunities for the Decentralised

Energy Master Plan — Renewable Energy.

This study was undertaken using research commissioned by the City of Sydney on

renewable electricity technology options by Arup, the City‘s proposed

Trigeneration network by Kinesis, and renewable gas resources by Talent with

Energy, as well as additional information in the public domain.

Background

The 14 renewable electricity technologies to be assessed for the Decentralised

Energy Master Plan — Renewable Energy is set out in Table ES.1 below.

Table ES.1

DECENTRALISED ENERGY MASTER PLAN - RENEWABLE ENERGY:

TECHNOLOGIES UNDER CONSIDERATION

Technology

Renewable electricity within the LGA – Building scale

Solar hot water Micro wind

Solar photovoltaic (PV)

Renewable electricity within the LGA – Precinct scale

Precinct scale wind turbines Concentrated solar thermal

Direct use geothermal

Renewable electricity beyond LGA

Onshore wind energy Concentrated solar thermal

Offshore wind energy Wave

Geothermal electric Tidal

Concentrated solar PV Hydro

Source: City of Sydney (2012).

In addition to the 14 technologies listed above, the potential for using four different

types of renewable substitute natural gas (SNG) resources as fuel for the City‘s

proposed Trigeneration network is also assessed, as set out in Table ES.2.


The Allen Consulting Group ix

Table 1.2

ALTERNATIVE RENEWABLE FUEL FOR THE TRIGENERATION NETWORK

Renewable Gas Resources

Renewable and synthesis gas from waste

Municipal solid waste + commercial & industrial waste (MSW + C&I)

Biomass (forestry and broadacre crop residue)

Large scale biogas (vegetable crops/horticulture, chicken and cattle manure)

Small scale biogas and landfill gas


Project objectives

The objective of this study is to evaluate the potential relative economic costs of

different electricity technology options that could be considered for use in

achieving the City of Sydney‘s targets for renewable electricity use and greenhouse

gas emissions abatement by 2030 under a particular macroeconomic scenario.

This study focuses on a comparison of the marginal social cost of abatement for

each of the 14 technologies and four gas resources that will enable the

determination of the optimal technology mix for achieving the City‘s renewable

electricity and emission reduction targets at least cost. The marginal social cost of

abatement represents the estimated cost of achieving a given quantity of greenhouse

gas emissions abatement, in this case, the real dollar cost of abating a tonne of

carbon dioxide equivalent emissions in 2012 prices.

This study is a high level evaluation of the economics of various electricity

technology generation options and is subject to a number of limitations, such as

uncertainty about future Australian macroeconomic developments, any future

changes in the government policy framework, project specific factors, such as

financing and taxation, and site-specific factors.

Limitations of the report

This report is not a detailed benefit and cost analysis of the City‘s Decentralised

Energy Master Plan – Renewable Energy, or of individual generation projects that

may form a part of the plan. The report provides an indication of various average

measures of the potential costs of different renewable energy technologies and

resources under consideration by the City of Sydney.

The results and findings presented in this report should be considered within the

limits of the constraints of the underlying analysis, which include the following:

only the cost of generation using each technology has been analysed;

– in addition, only average generation costs have been modelled, the cost of

generation using each technology at specific sites would be expected to

vary from this average;

disruption costs associated with constructing building and precinct scale

generators throughout the City, including disruptions to traffic, have not been

accounted for;


The Allen Consulting Group x

disruption costs associated with alterations to the transmission and distribution

network resulting from the implementation of these technologies, or from the

transportation of gas to the City have not been analysed;

a detailed commercial analysis, including the impact of adopting the renewable

technologies as part of the City‘s renewable energy master plan on prices and

competition in the electricity sector has not been undertaken;

while allowances have been made for the likely impacts of replacing grid

electricity with local renewable sources, these impacts have not been directly,

explicitly analysed due to limitations in information availability; and

the modelling results reflect possible outcomes that could occur under three

different macroeconomic, industry, and policy environment scenarios;

– differences between the modelled scenarios and actual macroeconomic,

industry, and policy environments would produce variations between the

modelled results and actual outcomes.

Main summary points

The marginal social cost of abatement for each of the renewable electricity

technology options and a number of comparator technologies, relative to the

baseline technology of black coal, is reported in Table ES.3.

Table ES.3 indicates that by 2030, the following electricity technology options

could potentially have negative marginal social costs of abatement by 2030:

micro wind;

Trigeneration (SNG – MSW + C&I);

Trigeneration (SNG – Small scale biogas);

building solar photovoltaic (PV); and

large scale onshore wind technology.


The Allen Consulting Group xi

Table ES.3

SUMMARY - MARGINAL SOCIAL COST OF ABATEMENT, REAL 2012 DOLLARS PER

TONNE OF CARBON DIOXIDE EQUIVALENTS (2012 $/TCO2-E)

Technology 2020 2025 2030

Solar hot water (Building) 67 41 26

Solar PV (Building) 23 -28 -65

Micro wind (Building) -17 -40 -53

Wind turbines (Precinct) 43 37 34

Direct use geothermal (Precinct) 49 37 26

Concentrating solar thermal (Precinct) 100 71 60

Onshore wind 19 9 -4

Offshore wind 113 106 90

Geothermal electric N/A 142 127

Concentrating solar PV 88 69 47

Concentrating solar thermal 175 141 129

Wave 247 150 133

Tidal 281 185 171

Hydro 126 121 117

Trigeneration (Natural Gas) 27 27 27

Black Coal with carbon capture & storage (CCS)

N/A 96 80

CCGT with CCS N/A 57 41

CCGT 85 83 69

Trigeneration (SNG - MSW + C&I) 0 0 0

Trigeneration (SNG - Biomass) 1 1 1

Trigeneration (SNG - Large scale biogas) 5 5 5

Trigeneration (SNG - Small scale biogas) -2 -2 -2

Source: Allen Consulting Group calculations (2013).

In interpreting the results presented in Table ES.3, the following points should be

taken into consideration:

The cost estimates represent the costs of electricity supplied from a ‗typical‘

generating unit of each technology type in NSW. However, the actual costs of

sourcing electricity supply from a generating unit of each technology type

located in the City of Sydney, the Greater Sydney region, or neighbouring

regions of NSW, will vary from this ‗typical‘ cost according to project and site

specific factors.

– These factors include the location and scale of the generator. Location

would impact on the generating capacity of wind, wave, hydro, and solar

generators in particular, as different sites would receive different amounts

of sunlight, rainfall, and wind in a given year.


The Allen Consulting Group xii

It is important to note that while a number of different renewable and low-

emission energy technology options have been estimated as potentially having

low or even negative marginal social costs of abatement by 2030, it is not

possible to completely source the City‘s electricity requirements from any one

of these sources, as they are subject to capacity constraints.

In particular, the building and precinct scale technologies are limited by the

amount of space available in the City to host the necessary equipment.

The renewable gas resources are also constrained by limits on their availability.

The gas will need to be sourced from dozens of different sites across the

Sydney Metropolitan Area and neighbouring regions.

– While it may be potentially economically viable to use these particular

sources of renewable gases as fuel for the Trigeneration network, it is

unclear if it would be commercially viable.

– The costs and complexities of sourcing small quantities of gas from dozens

of sites across NSW may render a number of renewable gas resource

options impractical.

SNG-Large scale biogas is the only renewable fuel that is capable of supplying

sufficient quantities of gas to meet the Trigeneration network‘s maximum

expected demand.

– If any of the other SNG options are selected, their cost would need to be

considered in conjunction with the cost of other gas sources that would be

needed to supply the full 27.6 PJ requirement of the City. This could range

from conventional natural gas to any of the other types of SNG.

– The analysis of the implication of the Trigeneration system being supplied

by several different types of natural gas resources and/or from multiple

suppliers of SNGs have not been undertaken for this report.

Large scale solar and wind power projects are currently operating or under

construction throughout NSW and the rest of Australia. However, they have

been assessed as being unviable in Greater Sydney and neighbouring regions of

NSW on average.

– As discussed earlier in this section, the costs and benefits associated with

specific generator projects vary from the average, depending on project

specific factors. Certain sites may generate benefits that are greater and

costs that are less than the average, which could result in it becoming

financially and economically viable even though the average site would not

be.

– Non-financial and non-economic factors may also affect the viability of a

particular electricity project. For example, government policy could

mandate the purchase of electricity from a renewable electricity supplier

that may not be the least cost supplier of electricity in order to achieve a

climate change mitigation, environmental, energy, regional, and/or industry

policy objective.


The Allen Consulting Group xiii

Conclusions and recommendations

This study represents a high level evaluation of the relative economic costs of

different renewable electricity technology options for achieving the City of

Sydney‘s renewable electricity and greenhouse gas abatement targets by 2030.

With few exceptions, most renewable electricity technologies assessed in this report

are not expected to become financially or economically viable within the timeframe

set for achieving the City of Sydney‘s renewable energy target under the given

macroeconomic and policy environment scenarios.

– Those technologies that may be potentially viable by 2020 and 2025 tend to

be small scale generators with serious capacity constraints that would limit

their ability to substantially reduce the City‘s reliance on grid electricity.

– The potential for large scale renewable electricity technology to replace the

City‘s use of grid electricity is not expected to be available until at least late

2020s. The cost of providing viable small scale electricity generators is also

expected to reduce further by then.

The costs and benefits of each technology type estimated in this report reflect that

of a ‗typical‘ or average example of a generating unit in NSW. However, project

specific factors would cause the costs and benefits associated with a particular

generator to vary from the average.

Furthermore, there are a number of important limitations to this study with regards

to key macroeconomic variables and a lack of information about the actual

commercial and financial arrangements under which investments in these

technologies would be made.

Therefore, this study should not be used as the basis for making investment

decisions regarding projects related to the electricity technologies evaluated in this

report. Detailed financial analysis of each individual project that account for project

specific factors not included in this report needs to be undertaken before decisions

can be made on any particular project.


The Allen Consulting Group 1

Section 1

Overview

Scope of report

The City of Sydney has engaged the Allen Consulting Group to conduct a financial

and economic analysis of renewable energy opportunities for the Decentralised

Energy Master Plan — Renewable Energy.


Energy Master Plan — Renewable Energy is set out in Table 1.1 below.

Table 1.1

DECENTRALISED ENERGY MASTER PLAN - RENEWABLE ENERGY:

TECHNOLOGIES UNDER CONSIDERATION

Technology

Renewable electricity within the LGA – Building scale

Solar hot water Micro wind

Solar photovoltaic (PV)

Renewable electricity within the LGA – Precinct scale

Precinct scale wind turbines Concentrated solar thermal


Renewable electricity beyond LGA

Onshore wind energy Concentrated solar thermal

Offshore wind energy Wave

Geothermal electric Tidal

Concentrated solar PV Hydro


In addition to the 14 technologies listed above, the potential for using four different

types of renewable gas resources as fuel for the City‘s proposed Trigeneration

network is also assessed, as set out in Table 1.2.

Table 1.2

ALTERNATIVE RENEWABLE FUEL FOR THE TRIGENERATION NETWORK

Renewable Gas Resources

Renewable and synthesis gas from waste

Municipal solid waste + commercial & industrial waste (MSW + C&I)

Biomass (forestry and broadacre crop residue)

Large scale biogas (vegetable crops/horticulture waste, chicken and cattle manure)

Small scale biogas and landfill gas




This report focuses on the economic aspects of delivering the renewable electricity

generating capacity that could potentially be used to achieve the targets of the

Master Plan and incorporates technical data produced by Talent With Energy and

ARUP for the City of Sydney, in addition to publically available information. It

presents estimates of the potential differences in the financial and economic cost of

the renewable energy technologies, and competing technologies.

All forecasts produced in this report represent estimates of the potential financial

and economic costs and benefits of each type of renewable electricity technology

based on particular scenarios about how the future of the Australian and

international economies will evolve out to 2050.

The estimates produced in this report depend on a number of key variables such as

changes in future global economic growth, energy prices, Australian electricity

prices, changes in the price of carbon, and government policy that are inherently

unpredictable. The implications of the analysis contained in this report will deviate

greatly depending on the scale of the variance between the actual values of these

economic variables and their values in the macroeconomic scenarios underlying this

analysis.

This report offers an analysis of the likely relative costs and benefits of the selected

renewable energy technologies at a high level, and do not take into account key

variables such as the financial structure of any entities that may be involved in

constructing, operating, and/or owning these technologies and resources, detailed

analysis of project specific taxation obligations, future borrowing costs, or site

specific costs, for example.

Investment or other financial decisions taken with regards to the renewable energy

technology and resource opportunities analysed in this report should not be taken

without seeking detailed, independent assessment of each particular project.

Green Infrastructure

Green Infrastructure to achieve reductions in greenhouse gas emissions and other

environmental objectives are one of the key elements of Sustainable Sydney 2030,

the City of Sydney's vision for a green, global and connected future. Currently, the

City has targets to achieve the following by 2030:

reduction in greenhouse gas (GHG) emissions by 70 per cent from 2006 levels;

zero reliance on coal fired electricity; and

30 per cent of the electricity consumed in the City to be from renewable

resources.

When completed, the City's Green Infrastructure Plan will comprise of five inter-

related Master Plans on:

Trigeneration;

Renewable Energy;

Advanced Waster Treatment;

Decentralised Water; and

Automated Waste Collection.



The Decentralised Energy Master Plan – Renewable Energy

The Master Plan has a major role in achieving a number of the City‘s environmental

objectives, such as:

its greenhouse gas emissions reduction targets;

the elimination of the City of Sydney‘s reliance on coal fired electricity; and

providing for 30 per cent of the City‘s electricity needs from local renewable

resources by 2030.

Electricity sourced from the grid is currently dominated by polluting, GHG

emission-intensive fossil fuel burning generators, which account for an estimated

90 per cent of Australia‘s electricity generation in 2011 (Department of the

Treasury 2011). The emission intensity of grid electricity in New South Wales is

estimated to be 1.06 tCO2-e/MWh, slightly above the national average of 1.03

tCO2-e/MWh (DCCEE 2012).

Australian Treasury (2011) modelling indicates that even with the carbon price

mechanism (CPM) and Renewable Energy Target (RET) in place, electricity

produced from fossil fuels is projected to make up between 64 and 80 per cent of

total generation by 2030, with emission intensity of electricity generation estimated

to average 0.61 tCO2-e/MWh.

Figure 1.1 charts the changes in the share of electricity generation technology in

Australia over time under the Carbon Price Mechanism as modelled by SKM MMA

and ROAM Consulting for the Australian Treasury (2011).

Figure 1.1

SOURCES OF ELECTRICITY GENERATION UNDER THE CARBON PRICE MECHANISM

SKM MMA ROAM

Source: Department of the Treasury (2011).



Another disadvantage of grid electricity in addition to relatively high carbon

intensity is that the generators feeding electricity into the grid tend to be located far

away from their end users. A significant amount of electricity is lost in delivery

through the transmission and distribution network. This lost energy adds to the

emission intensity of grid electricity.

With the City of Sydney local government area (LGA) being connected to the

National Electricity Market network, the LGA‘s power can be sourced from

generators located throughout the eastern mainland states and Tasmania. Local

renewable energy sources can offer electricity generation with zero carbon

emissions from generation and minimal transmission and distribution losses.

With the City of Sydney forecast to consume 4.3 TWh of electricity per year by

2030, its renewable electricity target of 30 per cent will require 1.3 TWh of

electricity to be produced from local renewable sources by 2030.

In addition, the Master Plan has a target of supplying up to 27.6 PJ of renewable

gases per year to replace the natural gas resource that will be used to supply the

372 MW of Trigeneration capacity identified in the Trigeneration Master Plan. This

will convert the Trigeneration capacity from a source of low emission electricity to

a near zero emission source, further reducing the City‘s GHG emissions and

displacing the use of fossil fuel fired electricity.

Electricity generation technologies


Energy Master Plan — Renewable Energy Master Plan all offer zero emissions

generation or displacement.

The City of Sydney has determined that 60 per cent of the renewable electricity

requirement identified under the Master Plan is to be sourced from within the City

of Sydney LGA by 2030, with the remainder to be sourced from beyond. Electricity

sourced from beyond the LGA will incur electricity losses in the transmission and

distribution network. However, generation capacity is intended to be sourced from

sites located within 250km of the LGA, limiting the losses.

Locations within approximately 250km of the City of Sydney are represented by the

area inside the red circle in Figure 1.2. The shaded red area represents the Greater

Sydney area while the City itself is denoted by a red balloon denotes the City.



Figure 1.2

LOCATIONS WITHIN APPROXIMATELY 250 KILOMETRES OF THE CITY OF SYDNEY

Source: Google (2013).

A comparison of the marginal social cost of abatement for each of the 14

technologies will enable the determination of the optimal technology mix for

achieving the City‘s renewable electricity and emission reduction targets at least

cost. Box 1.1 provides an explanation of the concept of the marginal social cost of

abatement.

Box 1.1

MARGINAL SOCIAL COST OF ABATEMENT

The marginal cost of abatement of a renewable electricity technology is equal to the

amount of emissions reduction that can be achieved using renewables instead of grid electricity, divided by the cost difference between renewable and grid electricity.

In contrast, the marginal social cost of abatement includes the cost faced by the

electricity supplier in reducing its greenhouse gas emission, in addition to any cost to the rest of society, such as:

subsidies offered by the government to encourage renewable electricity; and

any costs faced by the end user of electricity that may result, such as the need for new equipment to utilise a certain electricity resource.

Benefits that may exist, such as any reduced transmission and distribution costs, and avoided carbon permit liabilities have been factored into the calculation. However, benefits such as climate change mitigation have not been factored in.



Of course, the optimal technology mix would also be subject to resource

constraints, such as the limited availability of suitable sites within Sydney and

neighbouring regions to host generation capacity that may be dependent on an

abundant supply of specific natural resources such as wind, sunlight, waves, and

rapid currents.

Renewable gas resources

The four renewable gas resources to be assessed for their potential use as a fuel

source for the City‘s proposed Trigeneration network all offer low to near zero

emissions alternatives to the use of conventional, non-renewable natural gas

resources.

The Trigeneration network is expected to be capable of providing Sydney with a

372MW local low-emissions electricity generating capacity by 2030 using

conventional non-renewable natural gas and/or local renewable substitute natural

gas resources.

Analysis of the cost of using alternative renewable gases as fuel for the

Trigeneration network is dependent on estimates of the cost of producing these gas

resources using feedstock from sites across the Sydney Metropolitan Area, and

nearby areas within NSW that have been prepared for the City of Sydney by

Talent with Energy. Projections of the future cost of conventional non-renewable

natural gas reported by the Bureau of Resource and Energy Economics (BREE) in

the Australian Energy Technology Assessment (AETA) 2012 form the baseline for

comparison.

Limitations of this report














accounted for;













different macroeconomic, industry, and policy environment scenarios.






Section 2

Our approach

There are four major steps to completing this financial and economic analysis of

renewable energy technology options for the Master Plan, as illustrated in

Figure 2.1:

Scenario development;

Financial analysis;

Economic analysis; and

Reporting findings and formulating conclusions.

Figure 2.1

STAGES OF THE ANALYSIS

Source: Allen Consulting Group (2012).

Scenarios

The costs and achievement of the renewable energy and emission reduction targets

of the Master Plan are dependent on the uptake of the renewable technologies.



Three scenarios representing different take up rates of the renewable technologies

were constructed to examine their impacts on the cost of delivering the Master Plan.

The take up of these renewable energy technologies will depend critically on their

prices relative to that of grid electricity. Alternatives to grid electricity that are

cheaper will be adopted, while those that are more costly will require subsidies to

render them commercially viable.

The carbon price is expected to have a major influence on the price of electricity,

and is modelled by the Australian Treasury (2011) to raise the wholesale price of

electricity in NSW by an average of 38 per cent from 2012-13 to 2016-17. Retail

electricity prices are modelled to be 10 per cent higher.

The three scenarios are based around three different carbon price trajectories to

2030. Higher carbon prices will drive up the cost of grid electricity, which would

increase the commercial viability and take up of renewable energy technologies and

resources.

Figure 2.2 sets out the three carbon price trajectories underlying the three scenarios.

Figure 2.2

CARBON PRICE PATHS BY SCENARIO (REAL 2012 DOLLARS PER TONNE OF CO2 EQUIVALENT EMISSIONS,

2012$/TCO2-E)

Source: Allen Consulting Group analysis (2013), Department of the Treasury (2011).



Central

This represents a medium uptake scenario, based on the ‗Government Policy‘

scenario carbon price trajectory and electricity price impacts. The City of Sydney‘s

renewable energy target is met by 2030.

High

Based on a world where Australia faces a significantly higher carbon price as the

result of more ambitious emission reduction targets, grid electricity prices are

higher than the central scenario, resulting in higher uptake of renewables. The

City‘s renewable target is exceeded by 2030.

Low

The low uptake scenario represents a world with slow carbon price growth,

resulting in low electricity prices and a relatively low rate of adoption of

renewables. The City‘s renewable target is only met by 2030 with higher subsidies.

While the trajectory of the carbon price under the Australian Government‘s carbon

price mechanism (CPM) plays a central role in the formulating of the three

scenarios due to their expected impacts on the price of electricity and renewable

energy in Australia, the future of the CPM is currently uncertain.

The Coalition Opposition has stated its intention to repeal the CPM and implement

an alternative climate change mitigation policy framework if it were to form

government following the federal election scheduled for 14 September 2013. It is

uncertain what impact this would have on electricity prices and renewable

electricity prices in particular.

Financial analysis

Financial analysis of each of the renewable energy technologies under the Master

Plan is centred on the levelised cost of energy (LCOE). The LCOE of each

technology is the minimum cost of energy at which a generator must sell the

electricity produced using that technology in order to achieve its target level of

return. The LCOE can be considered as the break-even price for each

technology/resource.

The LCOE of each type of generation capacity is dependent on the following

factors:

capital costs – the costs of acquiring and installing the generation capacity;

fixed operating costs – the costs of operating the generators that is independent

of the actual output;

variable operating costs – costs of operating the generators that varies with

output generated;

fuel costs – the costs of any fuel that may be required by the generator to

produce electricity;

carbon price – the price of carbon permits under the Australian Government‘s

carbon price mechanism;



capacity factor – technical, regulatory and market constraints on the output of

the generator;

the discount rate – the interest rate at which future cash flows are discounted to

give their present value to enable a comparison between alternative uses of the

funds in the present on a consistent basis. The rate selected is 9.79 per cent,

which is the weighted average cost of capital (WACC) adopted by the

Australian Energy Market Operator (AEMO) for the Decentralised World

scenario of the 2010 National Transmission Network Development Plan

(NTNDP); and

the amortisation period – the period over which the LCOE is calculated, and

can be based on the estimated operating life of each generation technology

before it is either refurbished or decommissioned.

Factors such as the effects of taxation, plant decommissioning costs at the end of its

useful life, and plant residual costs are excluded from the calculation of the LCOE,

in keeping with the methodology adopted in the Bureau of Resource and Energy

Economics (BREE) 2012 Australian Energy Technology Assessment (AETA).

The LCOE calculation includes the value of any federal and state government

subsidies available to each technology. These include the Large-scale Generation

Certificates (LGCs) and Small-scale Technology Certificates (STCs) that are

available to renewable energy generators under the Australian Government‘s

Renewable Energy Target, and feed in tariffs that are made available to renewable

energy generators by the NSW Government.

Note that details of the new feed in tariff regime in NSW to replace the previous

scheme that was closed to new entrants by the NSW Government in 2011 have not

yet been finalised. The feed in tariff scheme assumed to operate in NSW for the

purposes of this analysis is based on the Independent Pricing and Regulatory

Tribunal (IPART) determination on ‗a fair and reasonable solar feed-in tariff for

NSW‘ of June 2012.

Appendix B sets out the methodology used to calculate the LCOE in detail.

After the LCOE is calculated, the ‗delivered cost‘ of each renewable electricity

technology can be calculated. The delivered cost of is equal to the LCOE with

network and distribution costs added. This represents the actual cost that is incurred

in delivering a unit of electricity from a generator using each type of technology, to

the final user.

Network charges are a major influence on the delivered retail price of electricity for

the end user. It is assumed that the large scale renewable electricity sourced from

beyond the LGA would be associated with network costs that would be comparable

to that of standard grid electricity as it would be dependent on the same

transmission and distribution network.

Precinct scale generators and even building scale generation technology may not

completely eliminate network costs. While it is true that those parts of the City that

are disconnected from the grid could avoid network charges, it is unlikely that

disconnection would occur. End users within the City of Sydney would require a

connection to the grid in order to:

export surplus electricity generation to the grid;



access grid electricity during periods of peak demand and/or any period where

the local generator capacity cannot adequately meet demand; and

maintain a high level of supply reliability in the event of the failure of the

building and precinct scale technology.

Any network cost savings that may be achieved are factored into the calculation of

the delivered cost of each electricity technology.

A necessary condition for a renewable technology to be financially viable is for the

delivered cost to be less than or equal to the delivered cost of the baseline electricity

technology, which is assumed to be black coal without CCS, the current primary

source of base load power in NSW.

However, this condition alone may not be sufficient for the project to be financially

and economically viable, as non-price factors such as reliability and security of

supply, government policies would also affect the viability of a generation project

incorporating any given technology.

The financial analysis is intended as a ‗vanilla‘ analysis of each technology and is

intended as a high level analysis of the relative costs of different technologies. It is

not intended as financial advice or as a basis for making investment decisions.

This analysis does not take key considerations such as the structure of the entity

undertaking the project, project specific borrowing costs and tax obligations, or site

specific costs.

The primary purpose of this financial analysis is as an input into the economic

analysis of the selected technologies.

Economic analysis

Economic efficiency is attained when the efficient level of total emissions reduction

is achieved at the lowest overall cost to society.

The marginal social cost of abatement for each of the fourteen renewable electricity

technologies, four renewable gas resources, and baseline technologies need to be

evaluated in order to compare their relative cost-effectiveness in achieving

greenhouse gas emissions abatement.

The methodology to be adopted for estimating the marginal social cost of abatement

of the renewable energy technologies and resources is based on that which the

Allen Consulting Group had previously used in evaluating the Decentralised Energy

Master Plan – Trigeneration.

Marginal social cost of abatement

The marginal social cost of abatement of each renewable technology is the basis by

which each of the fourteen technologies and four renewable gas resources would be

assessed for their potential economic viability as a source of renewable electricity

generation for the City of Sydney. This cost measure is made up of two concepts:

social cost; and

marginal cost.



Social cost

The social cost of taking a particular action, such as adopting renewable electricity,

refers to the costs incurred collectively by the entire society in taking that action. In

the context of this report, society refers to all residents, businesses, government, and

other entities operating within the City of Sydney, as well as those with activities

located in the City. This includes the electricity generators and network operators

who may be geographically located far from the City.

Marginal cost

The marginal cost of an action is the additional cost that is incurred in taking that

action. Returning to the renewable electricity example, the marginal cost is the

difference in cost between sourcing electricity from a renewable generator and from

a coal fired power plant, which is the baseline technology. Marginal social cost

then, is the marginal cost of taking an action that is faced by the entire society.

This concept is graphically illustrated in Figure 2.3.

Figure 2.3

MARGINAL SOCIAL COST


The marginal cost of an activity can change over time, due to a number of factors,

including technological improvements. In the example illustrated in Figure 2.3, the

marginal social cost of renewable technology falls from $10 in 2012 to $0 in 2020.

However, renewable electricity produced from renewable technology installed in

2012 will still have the 2012 marginal social cost of $30 in 2020, even though

electricity produced from renewable technology installed in 2020 would have a

marginal social cost of $20.



The logic behind this is straightforward. A simple explanation of this is that even

though technology is cheaper in 2020, that doesn‘t reduce the price that society paid

to install the technology back in 2012.

In this report, the marginal social cost of abatement refers to the social cost of

achieving a unit of greenhouse gas reduction or avoidance, as measured in terms of

tonnes of carbon dioxide equivalents (tCO2-e).

Box 2.1 explains the concept of and method of calculating the marginal social cost

of abatement in greater detail.

Box 2.1

CALCULATING THE MARGINAL SOCIAL COST OF ABATEMENT

Renewable electricity technologies abate greenhouse gas emissions by replacing the use of emissions intensive fossil fuel powered generators. However, renewable electricity technologies tend to be more expensive than non-renewables.

The difference between the cost of generating electricity using black coal generators and a particular renewable technology can be considered the cost of abating greenhouse gas emissions. When this cost is divided by the amount of greenhouse gas emissions avoided (measured in tonnes of CO2 equivalents, or tCO2-e), this provides the cost of abatement on a dollars per tCO2-e ($/tCO2-e) basis.

Each of the renewable electricity technologies to be assessed produces low emissions electricity at a different cost. The lowest cost technology should be used to replace emission intensive fossil fuel based electricity generators, such as the black coal baseline technology.

However, there may be constraints to how much electricity each technology type can provide to the city. These constraints may stem from need to balance between different technologies to ensure supply reliability, or natural physical limits, such as land availability, the amount of sunlight hours available at different points for solar technologies, or the availability of sufficiently windy sites for wind power.

As such, each technology type is capable of providing only a certain amount of low emissions electricity. In other words, at each cost level, a certain renewable electricity technology can provide a limited amount of emissions abatement potential. If additional abatement is required, the deployment of the next cost-effective technology is required.

The marginal abatement cost curve is a curve that plots out the amount of emissions abatement that is available at each cost level through different technologies. It is marginal in that it provides an indication of the additional cost that is required to achieve additional quantities of emissions abatement.

The marginal social cost of abatement curve takes into account both private and social costs of abatement, that is the cost to those directly involved in producing the renewable electricity, as well as any additional costs imposed on society, such as any government subsidies or a requirement for the adoption of new equipment by consumers in order to gain access to the renewable electricity.

The following example provides a basic explanation of how the marginal social cost

of abatement of a technology can be calculated.

If replacing 1 unit of coal fired electricity with 1 unit of renewable

electricity reduces the amount of greenhouse gas emissions by 1tCO2-e;

and

1 unit of renewable electricity cost society $1 more than 1 unit of coal fired

electricity; then

the marginal social cost of abatement of renewable electricity is $1/tCO2-e.



Therefore, the marginal social cost of abatement of replacing a portion of the City

of Sydney‘s grid-sourced electricity with a particular renewable electricity

generator is the cost that is borne by everyone who conducts activities in or is

economically connected to the City, such as residents, businesses, government, and

the electricity supply industry.

However, as the marginal social cost of abatement is an indication of the cost borne

by society in total, it does not offer an indication about who specifically within

society bears the cost.

In summary, the marginal social cost of abatement of a technology in a given year

is the cost of achieving an additional unit of greenhouse gas abatement using

equipment featuring that technology that was produced in the particular year.

A social marginal abatement cost (MAC) curve is produced by graphing the

marginal social cost of abatement (or social MAC) of every technology under

comparison on a single curve, in order from the lowest cost to the highest cost, or

vice versa. This provides a visual representation of the cost of achieving an

additional unit of abatement using each technology in a given year.

Figure 2.4 is an example of a marginal social abatement cost curve.

Figure 2.4

EXAMPLE MARGINAL SOCIAL COST OF ABATEMENT: RENEWABLE ELECTRICITY TECHNOLOGIES IN 20XX (REAL

2010 DOLLARS PER TONNE OF CO2 EQUIVALENT OF EMISSIONS ABATEMENT)




This approach accounts for:

the cost of any subsidies that will be necessary to support the commercial

viability of each technology; and

any additional cost borne by the final consumer of electricity from adopting a

particular technology.

In addition, the methodology for assessing the social cost of carbon abatement from

renewable gases will incorporate the following assumptions:

renewable gases to be generated locally (within 250km);

gas would be:

– converted to substitute natural gas and injected in the existing natural gas

pipeline; or

– liquefied and transported directly into the city; and

renewable gases would be used in the City‘s Trigeneration units to generate

electricity and thermal energy and displace grid fired electricity.

The costs involved with these specific assumptions for sourcing renewable gases

have been factored into the methodology for assessing the social cost of abatement

of this technology.

As with the financial analysis upon which it is built, this economic analysis does

not take into account a number of project and site specific factors that are necessary

for an assessment of the economic costs and benefits of individual energy projects.

It is also dependent on future macroeconomic scenarios that were constructed using

publicly available information at the time of writing, such as the Australian

Treasury‘s Strong Growth, Low Pollution: Modelling a Carbon Price report,

released in 2011.

The methodology for undertaking this study of renewable electricity technologies

and renewable gas resource options under the City of Sydney‘s Decentralised

Energy master Plan – Renewable Energy, as set out in this section, is in line with

that previously used to undertake the financial and economic analysis of the City‘s

Trigeneration Master Plan by the Allen Consulting Group in conjunction with

Kinesis in 2012.

Assumptions

Underlying the financial and economic analysis of the technologies that could

potentially be adopted under the master plan are assumptions about the

macroeconomic environment from the present to 2030-31 as well as the

development and availability of the technologies.

Economic assumptions

Economic variables that could affect the financial and economic viability of the

technologies to be evaluated under the master plan include:

the carbon price;



the Large-scale Generation Certificate (LGC) and Small-scale Technology

Certificate (STC) prices under the Australian Government‘s Renewable Energy

Target (RET); and

electricity prices.

The economic assumptions underlying this report are based on the Government

Policy scenario of the Australian Treasury‘s Strong Growth, Low Pollution:

Modelling a Carbon Price (SGLP) report released in July 2011 and subsequent

updates released in September 2011.

In particular, the carbon price trajectories modelled in the SGLP report have a major

impact on the results of this analysis. However, since the publication of the SGLP

report in July 2011 and subsequent revisions in September 2011, there have been

further changes to the Carbon Price Mechanism (CPM) which would affect

Australian carbon prices in the future.

This includes the proposed linkage of the Australian CPM to the European Union

Emissions Trading Scheme (EU ETS) at the conclusion of the fixed price trading

period in 2015 and the consequent removal of the CPM floor price. The likely

impact of these changes on the carbon price remains uncertain.

Appendix A sets out the economic assumptions in greater detail.

Technical assumptions

Estimates of the capital costs for the fourteen renewable electricity technologies and

four renewable gas resources were produced by combining cost estimates of each

type of technology using up to date estimates contained in the AETA and public

domain information with the information to be provided by the City on the types,

scales and locations of the renewable energy sources to be installed.

Developments of comparator and competitor generation technologies such as black

coal and gas fired power plants, carbon capture and storage (CCS) technology, also

need to be taken into account.

Appendix C sets out the technical assumptions underlying the electricity technology

in detail while Appendix D sets out the renewable gas resources assumptions.



Section 3

Financial analysis

Results from a financial analysis of the renewable electricity technologies are

presented in this section. The analysis focuses on the differences between the cost

of delivering a megawatt hour (MWh) of electricity using each renewable

technology and coal fired electricity, the baseline technology.

The capital costs of each technology are assumed to be constant for all three

scenarios, although the delivered cost varies under the different scenarios due to the

impact of the carbon price on the LCOE of emission intensive comparator

technologies. The financial analysis focuses only on the Central scenario, as

described in Section 2.

As explained in Section 2, the financial analysis conducted in this report is based on

generic assumptions for each type of technology, and a macroeconomic forecast

scenario as set out in Section 2 and elaborated on in Appendix A. It should be

considered as a high level assessment of the relative costs of each type of electricity

generation technology, given the macroeconomic environment scenario adopted for

this study.

This analysis cannot be considered as an assessment of the financial viability of a

particular project or considered as financial advice for any particular investment

project as it does not account for project specific factors relating to tax concessions,

actual borrowing costs, and other limitations as specified in Section 2.

The cost estimates reported in this section reflect the average cost of constructing

and operating generation capacity using each type of technology. However the per

unit cost of operating and constructing a particular generation facility would vary

with the size and capacity of the facility.



Capital expenditures

The estimated capital costs of constructing generating capacity using each type of

renewable energy technology and resources in is presented in Table 3.1.

Where available, capital cost estimates are drawn from the 2012 AETA. Estimates

for the remaining technologies were produced using other public domain

information.

Table 3.1

ESTIMATED CAPITAL COST BY RENEWABLE ENERGY TECHNOLOGY, REAL 2012

DOLLARS PER MEGAWATT OF INSTALLED CAPACITY ($/MW)

Technology / Resource 2012 2020 2025 2030

Building integrated within LGA

Solar hot water 2,935,000 2,801,000 2,720,000 2,642,000

Solar PV 4,295,000 3,458,000 2,993,000 2,590,000

Micro wind 4,885,000 3,353,000 3,360,000 3,406,000

Precinct scale within LGA

Wind turbines 3,732,000 2,562,000 2,567,000 2,602,000

Direct use geothermal 314,000 300,000 291,000 283,000

Concentrating solar thermal 8,282,000 5,116,000 4,461,000 4,457,000

Renewable electricity beyond the City

Onshore wind 2,579,000 1,771,000 1,774,000 1,799,000

Offshore wind 4,538,000 3,978,000 4,043,000 3,942,000

Geothermal electric 10,943,000 11,010,000 11,067,000 10,979,000

Concentrating solar PV 3,822,000 2,434,000 2,290,000 2,138,000

Concentrating solar thermal 4,888,000 2,997,000 2,599,000 2,611,000

Wave 6,118,000 6,193,000 3,951,000 3,807,000

Tidal 6,175,000 6,251,000 3,988,000 3,843,000

Hydro 3,620,000 3,486,000 3,400,000 3,316,000

Baseline technology

Black coal 1,548,000 1,861,000 2,054,000 2,248,000

Source: Allen Consulting Group calculations (2013), Bureau of Resource and Energy Economics (2012), CSIRO (2011) and EPRI (2006).

Operating expenditures

The costs of operating electricity generators fall under two categories: fixed, and

variable.

Fixed operating costs include1

:

direct labour costs and associated support costs;

fixed service provider costs;

1

BREE (2012, p.19).



minor spares and fixed operating consumables; and

fixed inspection, diagnostic and repair maintenance services.

Estimated annual fixed operating costs are reported in Table 3.2 in terms of cost per

MW of installed capacity ($/MW per year).

Table 3.2

ESTIMATED FIXED OPERATING COST BY RENEWABLE ENERGY TECHNOLOGY,

REAL 2012 DOLLARS PER MEGAWATT OF INSTALLED CAPACITY ($/MW PER YEAR)



Solar hot water 111 118 123 128

Solar PV 0 0 0 0

Micro wind 338 361 376 391


Wind turbines 42,939 45,921 47,785 49,649

Direct use geothermal 81,238 86,881 90,407 93,934

Concentrating solar thermal 60,000 64,168 66,772 69,377


Onshore wind 40,000 42,778 44,515 46,251

Offshore wind 80,000 85,557 89,030 92,503

Geothermal electric 170,000 181,808 189,188 196,568

Concentrating solar PV 38,000 40,639 42,289 43,939

Concentrating solar thermal 60,000 64,168 66,772 69,377

Wave 190,000 203,197 211,445 219,693

Tidal 270,491 289,279 301,021 312,764

Hydro 40,357 40,357 40,357 40,357

Baseline technology

Black coal 31 37 41 45


Variable operating costs include2

:

chemical and operating consumables that are generation dependent, such as raw

water, and water treatment chemicals;

scheduled maintenance of the entire plant; and

any unplanned maintenance.

Estimated variable operating costs are presented in Table 3.3 in terms of cost per

MWh of generation sent out ($/MWh).

2

BREE (2012, p.19)



Table 3.3

ESTIMATED VARIABLE OPERATING COST BY RENEWABLE ENERGY

TECHNOLOGY, REAL 2012 DOLLARS PER MEGAWATT HOUR OF GENERATION

SENT OUT ($/MWH)




Solar PV 2 2 2 2

Micro wind 0 0 0 0


Wind turbines 11 11 12 12

Direct use geothermal 0 0 0 0

Concentrating solar thermal 15 16 17 17


Onshore wind 12 13 13 14

Offshore wind 12 13 13 14

Geothermal electric 0 0 0 0

Concentrating solar PV 0 0 0 0


Wave 0 0 0 0

Tidal 0 0 0 0

Hydro 2 2 2 2

Baseline technology

Black coal 9 11 12 14


Delivered Cost

On the basis of the capital and operating costs presented above, the estimated

LCOE and delivered cost for each technology was calculated. As explained in

Section 2, the delivered cost represents the minimum price that electricity produced

by each technology need to be sold at, inclusive of transmission and distribution

costs, in order to break even.

The estimated delivered cost of each renewable electricity technology and the

baseline technology is presented in Table 3.4 in terms of cost per MWh of

generation ($/MWh).



Table 3.4

ESTIMATED DELIVERED COST BY RENEWABLE ENERGY TECHNOLOGY, REAL 2012

DOLLARS PER MEGAWATT HOUR OF GENERATION ($/MWH)




Solar PV 292 242 204 180

Micro wind 299 196 190 194


Wind turbines 335 264 276 291

Direct use geothermal 261 270 276 282



Onshore wind 245 233 243 250

Offshore wind 323 321 333 337

Geothermal electric 338 356 366 371

Concentrating solar PV 358 298 299 296


Wave 424 446 374 376

Tidal 455 478 407 412

Hydro 316 333 347 362

Baseline technology

Black coal 191 215 235 253

Source: Allen Consulting Group calculations (2013), Bureau of Resource and Energy Economics (2012) and CSIRO (2011).

Conditional viability

A comparison of the cost estimates in Table 3.4, indicate that the following

renewable technologies could possibly be delivered at a lower cost than black coal

fired electricity by 2030 under the macroeconomic forecast scenario adopted for

this report:

building solar photovoltaic (PV);

building micro wind; and

large scale onshore wind.

Cost of the Decentralised Energy Master Plan – Renewable Energy

Using the per kilowatt capital costs from Table 3.1, an estimate of the cost of

constructing the generation capacity required to meet 30 per cent of the City of

Sydney‘s total electricity requirements with renewables under the Central Scenario

of the Master Plan was produced. It is assumed that least cost technology options as

identified in Table 3.4 are used to provide the required generation capacity.



Under the scenario, 30 per cent (1.3TWh) of the City of Sydney LGA‘s annual

electricity demand in 2030 would be supplied by the following technology mix:

building integrated renewables within the LGA supply 23.1 per cent

(297.9 GWh per year), costing $716.7 million from 2012 to 2030 ($210.7

million in 2012 dollars when discounted using a 9.79 per cent nominal rate);

76.9 per cent (994.3 GWh per year) is generated by renewable sources from

beyond the City of Sydney, costing at least $535.5 million (or $129.9 million in

discounted terms), assuming the use of onshore wind technology.

Note that the finding that 23.1/76.9 per cent split between renewable electricity

sources within the City of Sydney LGA and those from beyond the LGA is based

on a methodology designed to determine the least cost method of delivering the

City‘s renewable electricity target.

This methodology also accounts for the resource constraints that apply to the

City, such as the limited availability of suitable sites to host building-scale solar

and wind generators within Sydney.

However, since the completion of this analysis, the City of Sydney has

determined that 60 per cent of the renewable electricity requirement under its

renewable electricity target would be sourced from within the LGA, while the

remaining 40 per cent would be sourced from beyond.

The differences between the latest design of the plan by the City of Sydney and

the version analysed in this section of the report should be kept in mind in

considering the implications of this analysis.

The differences between the version of the plan analysed in this section and the

current version of the City‘s only affects the plan‘s technology mix, not the

costs and benefits of each technology. That is, the analysis of the costs and

benefits of each individual technology are unaffected by these differences.

Figure 3.2 provides a breakdown of the installed generation capacity by technology

that would be required under this scenario. Building integrated renewable

represents 1MW of capacity in 2020, growing to 121MW by 2025 and 243 by 2030.

Beyond LGA renewables make up 300MW of installed capacity by 2030, for a total

renewable capacity of 543MW.

Precinct scale renewables cannot provide capacity at a sufficiently low cost to enter

the renewable electricity generation capacity mix in this scenario.



Figure 3.2

CENTRAL SCENARIO, MEGAWATTS OF INSTALLED RENEWABLE ELECTRICITY

GENERATION CAPACITY. 2020 TO 2030 (MW)


Overall, the implementation of the Decentralised Energy Master Plan – Renewable

Energy from 2012 to 2030 , using the least cost mix of technologies, is estimated to

require at least $1,252.2 million (or at least $340.7 million in discounted terms) in

capital costs.

Figure 3.3 provides a breakdown of the generation share and capital cost share of

each technology type under the Central scenario of the master plan.



Figure 3.3

DECENTRALISED ENERGY MASTER PLAN – RENEWABLE ENERGY: CENTRAL SCENARIO, ELECTRICITY

GENERATION AND CAPITAL COST BY TECHNOLOGY (PER CENT SHARE)


Given construction lead times, it is assumed that work will have to begin on the

onshore wind generators by 2026 in order to ensure that sufficient renewable energy

capacity is available to allow the city to achieve its 2030 target.

However, as onshore wind is not expected to be commercially viable until at least

2029, an estimated subsidy of between $1.00 and $6.00 per MWh is required to

enable the provision of electricity from this source to be competitive with output

from the baseline black coal plant.

A breakdown of the delivered cost of onshore wind power between the baseline

technology (black coal) delivered cost and the subsidy required is displayed in

Figure 3.4.



Figure 3.4

COMPONENTS OF THE DELIVERED COST OF ONSHORE WIND, REAL 2012

DOLLARS PER MEGAWATT HOUR (2012 $/MWH)


This estimate is for an average onshore wind generation facility in average NSW

conditions. The viability of a specific onshore wind generation project would vary

depending on site specific factors, such as wind availability and site accessibility.

Indeed, there are currently onshore wind facilities in operation or under

construction throughout Australia. However, there are a number of factors

influencing the viability of these sites, many of which are unlikely to be applicable

to future projects, such as renewable energy support schemes at the state and federal

levels that may no longer be in operation or available to new projects, or may be

due to non-financial factors.

For example, the NSW Government had signed an agreement to purchase

renewable energy from the Capital Wind Farm in Southern NSW for 20 years to

provide a 100 per cent offset for the Kurnell Desalination Plant‘s power

requirements in order to fulfil a specific policy objective of powering the

Desalination Plant with renewable energy.

The Renewable Energy Target, together with the Carbon Pricing Mechanism,

continues to provide incentives for the construction of low greenhouse gas

emissions electricity generation technologies. However there is an element of risk

associated with electricity generation projects with viability that is dependent on the

RET and CPM. These instruments exist under Commonwealth legislation and

regulations that are subject to change at discretion of the government of the day.



The RET is due to terminate in 2030, and the CPM‘s future is uncertain given the

Coalition Opposition‘s stated intent to repeal the scheme if it succeeds in forming

government following the federal election scheduled for 14 September 2013.

Financial analysis - summary and conclusion

On average, it appears that only three renewable electricity technologies could

potentially offer alternatives to grid electricity to the City of Sydney by 2030 that

would be unlikely to require additional subsidies under the macroeconomic

environment portrayed in the Central scenario:

building solar photovoltaic (PV);

building micro wind; and

large scale onshore wind.

That is, these are the three technologies projected to on average to have the

potential to provide electricity at a lower delivered cost than coal-fired electricity

supplied through the grid. However, the performance of individual electricity

generation projects would vary from the average depending on site and project

specific factors that cannot be accounted for in the absence of project specific

information. Changes in the macroeconomic, legislative, regulatory, and policy

environment from that modelled under the Central scenario would also affect the

implications of this analysis.

An assessment of the financial viability of a specific renewable electricity

generation project would require project specific factors, and could vary from the

implications of the high level financial analysis of the average example of each type

of technology presented in this section.



Section 4

Economic analysis

Results from an economic analysis of the renewable electricity technologies are

discussed in this section. The focus is on the greenhouse gas abatement achievable,

and the marginal social cost of abatement under each scenario.

Potential greenhouse gas abatement

Figure 4.1 illustrates the amount of renewable electricity that could be produced by

the capacity installed under the master plan from 2012 to 2030 under each scenario.

All three scenarios achieve the target of 1.3 TWh by 2030.

Figure 4.1

ELECTRICITY SUPPLY PER YEAR BY SCENARIO, TERAWATT HOURS PER YEAR (TWH/Y)


On the basis of the analysis in Section 3, it is apparent that renewable electricity

technologies would not begin to become financially viable until 2020.

Through displacing generation from non-renewable, emission intensive power

plants, the cumulative greenhouse gas emissions abatement achievable under each

of the three scenarios from 2012 to 2030 are as follows:



3.0 MtCO2-e under the Central scenario;

6.5 MtCO2-e under the High scenario; and

2.6 MtCO2-e under the Low scenario.

The 2030 renewable energy target is estimated to be achieved by 2027 under the

High scenario, but is not expected to be achieved until 2030 under the other two

scenarios.

Figure 4.2 illustrates that cumulative greenhouse gas emissions abatement that

could be achieved from 2012 to 2030 under each of the three scenarios.

Figure 4.2

CUMULATIVE GREENHOUSE GAS EMISSIONS ABATEMENT ACHIIEVED BY SCENARIO (MTCO2-E)



The marginal social cost of abatement under each scenario at 2020, 2025, and 2030

for each scenario are presented over the remainder of this section. Black coal

without CCS is the baseline technology used for this analysis.

In relation to the City of Sydney‘s renewable energy target, the marginal social cost

of abatement can be considered as the cost of achieving the abatement of a tonne of

carbon dioxide equivalent greenhouse gas emissions using each of the different

technologies.



In order to achieve abatement at least cost, the City‘s targets should be achieved by

using the combination of technologies that are capable of meeting the City‘s

electricity needs at the lowest price. However, other considerations could influence

the choice of technologies, such as safety, aesthetics, reliability, and security of

supply, for example.

Abatement costs reported for each year represents the relative costs of adopting

each type of technology in that year. For example, if a technology is considered to

be viable in 2030, it indicates that it is viable if it is constructed in 2030.

However, if the same type of technology was installed in an earlier year, such as

2025, its marginal social abatement cost in 2030 would reflect the cost reported for

that year (2025) rather than 2030, as its construction costs are already locked in to

2025 levels.

The exception is for the Trigeneration technologies. It is assumed that construction

of the Trigeneration network begins in 2013.

Central Scenario

Figure 4.3 presents the estimated marginal social cost of abatement of each of the

renewable electricity technologies that are available by 2020 and a number of

comparator technologies:

the City of Sydney‘s Trigeneration master plan; and

Combined Cycle Gas Turbine (CCGT).

Note that geothermal electric is not yet available by 2020. Two additional

comparator technologies are also not yet available at this point in time:

CCGT with carbon capture and storage (CCS); and

black coal with CCS.

Note that the estimates for Trigeneration are simply based on the figures reported in

the Trigeneration Master Plan and adjusted for 2012 prices to provide a common

base of comparison.

This analysis indicates that micro wind would potentially have a negative marginal

social cost of abatement by 2020. A negative marginal social cost of abatement

suggests that for the City as a whole, including the generators (which may be

located beyond the City), it is cheaper to produce electricity using the cleaner

technology than the more polluting baseline technology of black coal.

However, it is uncertain where this benefit of reduced cost accrues to. That is, it is

uncertain whether households, the Council, the generators, other parties, or some

combination of them all, would capture the benefits.

The marginal social cost of abatement curve indicates that under the Central

Scenario, in 2020, micro wind (building) on average represents the lower cost

option for achieving the City‘s renewable energy target, with a negative marginal

social cost of abatement ($-17/tCO2-e). This indicates that on average, micro wind

(building) has the potential to simultaneously deliver greenhouse gas abatement and

electricity cost savings.



Figure 4.3

MARGINAL SOCIAL COST OF ABATEMENT: CENTRAL SCENARIO, 2020 (REAL 2012 DOLLARS PER TONNE OF CO2

EQUIVALENT OF EMISSIONS ABATEMENT)

Source: Allen Consulting Group analysis (2013).

However, the potential of micro wind (building) as a source of clean energy for the

City of Sydney is limited by constraints in a key resource: space. It is unlikely that

there will be sufficient suitable sites available within the City of Sydney for the

construction of micro wind (building) generators in the quantity necessary to

displace a significant proportion of the City‘s electricity demand that is currently

supplied by grid electricity.

Tidal electricity appears to be possibly the most expensive option, on average, at

$281/tCO2-e.

However, even within the assumptions of this scenario, it is possible for the cost of

constructing individual generation units using each technology to vary from the

average cost, depending on site/project specific factors, such as the size and scale of

the generation unit.



Figure 4.4 presents the estimated marginal social cost of abatement by 2025. All

technologies are expected to be available by 2025, with building solar PV ($-

28/tCO2-e) and micro wind ($-40/tCO2-e) estimated to have potentially negative

abatement costs. Tidal power remains as the technology with the highest cost under

this scenario, at $185/tCO2-e).

Figure 4.4




Only building scale renewable electricity technologies are considered to be capable

of delivering abatement and cost savings simultaneously on average under this

scenario by 2025.

Due to the capacity constraints associated with building scale technology flowing

from the limited availability of suitable locations within the City of Sydney, it is

unlikely that these technologies would be able to deliver renewable electricity

generation capacity in sufficient quantities and with acceptable levels of reliability

to enable the City to end its reliance on grid electricity by 2025 under this scenario.



Estimates of the marginal social cost of abatement by 2030 are presented in Figure

4.5. At this time, large scale onshore wind technology is also estimated to

potentially have negative marginal social costs of abatement ($-4/tCO2-e).

Overall, under the Central Scenario, it appears that on average, large scale

renewable electricity technology is not likely to become viable until at least until

the late 2020s. Even then, only onshore wind generators located beyond the City of

Sydney is potentially capable of providing large scale renewable generation

capacity.

Figure 4.5




Small, building scale technology would probably have a major role in providing

generation capacity in the early years of a renewable electricity rollout plan based

on this scenario. Under such circumstances, it is likely that the City of Sydney

would need to rely upon access to grid electricity in order to ensure security of

supply, as the output of wind power generators are dependent on prevailing weather

conditions.



High Scenario

A major feature of this scenario is the importance of the carbon price as a major

driver of the viability of renewable technologies, particularly in the later years, due

to its impact on emissions intensive generators.

Conversely, the RET has a smaller role in the viability of electricity generation

technologies under this scenario as the high carbon price is assumed to drive an

expansion of renewable electricity capacity to the extent that the role of the RET in

fostering the development of renewable electricity in Australia becomes redundant.

Figure 4.6 presents the potential marginal social cost of abatement of each of the

renewable electricity technologies that are available by 2020.

Figure 4.6

MARGINAL SOCIAL COST OF ABATEMENT: HIGH SCENARIO, 2020 (REAL 2012 DOLLARS PER TONNE OF CO2



Under this scenario, only building scale micro wind is estimated to potentially have

a negative marginal social cost of abatement ($-30/tCO2-e) by 2020. At

$263/tCO2-e, tidal power remains, on average, the most expensive potential source

of renewable electricity for the City under this scenario.



It is estimated that by 2025, building scale solar PV (rooftop solar panels), and large

scale onshore wind would also each potentially have a negative marginal social cost

of abatement, as shown in Figure 4.7. Building micro wind is expected to remain

the lowest cost potential source of renewable electricity for the City on average in

2025 under this scenario.

Although there is expected to be a wider range of generation technology that could

potentially offer renewable electricity and greenhouse gas abatement at below

baseline technology costs by 2025 under this scenario, it is unlikely that the City

would be able to end its reliance on grid electricity without a substantial increase in

energy costs at this point.

Figure 4.7



Source: Allen Consulting Group analysis (2013)

The building and precinct scale technologies are constrained by the limited

availability of suitable sites within the City, while onshore wind and the two

building scale technologies are also limited by dependence on favourable weather

conditions.



Figure 4.8 shows that although the marginal social cost of abatement may

potentially fall further for all technologies by 2030, no additional technologies are

expected to have potentially negative abatement costs.

Although this is the most optimistic of the three scenarios for renewable electricity

technologies, there are very few technologies that may potentially be economically

viable for inclusion into the City‘s plan even under the High Scenario.

Figure 4.8




As in the Central Scenario, only onshore wind is expected to be an economically

viable potential source of large scale renewable electricity by 2030 under the High

scenario.

Due to limitations on the reliability and availability of potentially economically

viable technologies, as discussed throughout this section of the report, it is unlikely

that the City would be able to completely substitute grid electricity with electricity

sourced from these renewable sources. However, the City may choose to draw on

other more expensive sources of renewable electricity that are available.



Low Scenario

Of the three scenarios, the Low Scenario offers the least favourable prospects for

the viability of renewable electricity technologies. Due to the low carbon price

trajectory underlying this scenario, the RET has a major role in encouraging

renewable electricity generation. The relatively low carbon price under this scenario

raises the marginal social cost of abatement compared to the other scenarios by

effectively increasing the cost differentials between the baseline coal-fired

electricity technology and renewables.

However, as a consequence of the lower carbon price, conventional coal-fired based

grid electricity would also be expected to be more heavily polluting than in the

other scenarios, which would exert a downward influence on the marginal social

cost of abatement for clean technologies relative to the other scenarios by allowing

for more greenhouse gas emissions abatement per MWh of electricity generated.

The Low Scenario represents a possible outcome that could result if there is no

rapid increase in the Australian Carbon Price following the end of the fixed price

period of the CPM in 2015. Other forces, such as economic growth, inflation, and

other macroeconomic factors could result in an outcome that is quite different to

that modelled in this scenario, even if the actual carbon price trajectory matches the

assumed trajectory. The marginal social cost of abatement of each of the renewable

electricity technologies that are available by 2020 under the Low scenario is

illustrated in Figure 4.9.

Figure 4.9

MARGINAL SOCIAL COST OF ABATEMENT: LOW SCENARIO, 2020 (REAL 2012 DOLLARS PER TONNE OF CO2





Of the renewable electricity technologies currently expected to be available by

2020, building scale micro wind is estimated to potentially have a negative

marginal social cost of abatement, at $-9/tCO2-e.

Under the Low scenario, it is estimated that by 2025, building solar PV would also

potentially have a negative marginal social cost of abatement, as shown in

Figure 4.10.

Figure 4.10




With a sustained, low carbon price trajectory, under this scenario, the marginal

social cost of abatement of most renewable electricity technologies, including all of

those offering large-scale generation, remain positive even by 2025. The absence of

a high carbon price is projected to maintain the competitiveness of coal-fired

electricity.

Trigeneration has a lower marginal cost of abatement under this scenario than in the

higher carbon price scenarios as it is assumed to be fuelled with fossil natural gas.

The lower carbon price would reduce the carbon price liability and hence the total

operating costs of the Trigeneration network relative to scenarios with higher

carbon prices.



It is estimated that no additional technologies would be likely to have a negative

cost by 2030, although the four technologies already with potentially negative cost

in 2025 may become even more negative, as presented in Figure 4.11.

Figure 4.11




Overall, it appears that under the assumptions of the Low Scenario, large-scale

renewable technologies are unlikely to become viable on average within the City of

Sydney. This is due to the expectation that a low carbon price would be unlikely to

raise the cost of baseline grid electricity by the amount necessary to close the cost

differential with renewable electricity technologies.

The relatively greater abatement per MWh of renewable electricity generated that

could be achieved under this scenario due to the expected higher level of baseline

emissions resulting from the low carbon price, is more than offset by the higher

marginal costs of renewables under this scenario. The end result is an overall higher

marginal social cost of abatement for all of the renewable technologies in this

scenario relative to the Central and High scenarios.



This suggests that the large-scale substitution of coal-fired grid electricity with

renewable electricity is unlikely to occur by this point of time through market

forces alone, under the given macroeconomic and policy environment. Additional

incentives may be necessary to encourage the large-scale uptake of renewable

electricity technologies under this scenario.

Economic analysis – summary and conclusion

A number of different renewable and low-emission energy technology options have

been estimated as potentially having low or even negative marginal social costs of

abatement by 2030 under the three scenarios.

However, it is important to note that it is not possible to completely source the

City‘s electricity requirements from any one of these sources, as they are generally

subject to capacity constraints. In particular, the building and precinct scale

technologies are limited by the amount of space available in the City to host the

necessary equipment.

The optimal mix of renewable electricity technologies for meeting the City of

Sydney‘s electricity demands with a renewable substitute for grid electricity is

dependent on both cost and capacity constraints.

Overall, the majority of the renewable electricity technologies assessed are on

average projected to have positive marginal social costs of abatement under all

three scenarios all the way to 2030. This indicates that the baseline technology of

coal-fired electricity sourced from the grid is likely to remain cheaper than most

renewable technologies, especially those with the potential for large scale

generation, within the macroeconomic, and policy parameters of the three scenarios

modelled.

As the positive marginal social cost of abatement for each renewable electricity

technology represents the average cost differential between that technology and

coal, it can also be considered as an estimate of the average minimum subsidy on a

$/tCO2-e basis that would be required to make this technology economically viable.

Conversely, technologies with negative marginal social costs of abatement indicate

that these technologies are on average likely to become economically viable even

without additional subsidies as they are projected to be capable of producing

electricity at costs below that of coal.

However, bear in mind that the marginal social cost of abatement refers to the costs

incurred by the entire society. A renewable electricity project incorporating an

economically viable technology may not necessarily be financially viable, and a

project making use of a technology that is not projected to be economically viable

on average, may turn out to be financially viable. The viability of any individual

electricity generation project is dependent on project specific factors.



Section 5

Trigeneration with renewable gas feedstock

Results from an analysis of the use of alternative local renewable gas resources as a

substitute for conventional non-renewable natural gas to fuel the City of Sydney‘s

planned 372MW Trigeneration network are discussed in this section.

According to the City‘s Trigeneration Master Plan, it is estimated that up to 27.6 PJ

of gas would be needed to fuel the city‘s Trigeneration network per year by 2030.

Renewable gas

Renewable natural gas is a type of substitute natural gas (SNG) produced by

refining biogas to a quality that is comparable to ―traditional‖ or ―fossil‖ natural

gas. At a basic level, biogas is a mixture of gases that is produced from the

decomposition of organic matter, such as agricultural, industrial, and municipal

waste.

While the chemical composition of fossil natural gas and renewable bio-SNG are

similar, differences in the environmental and global warming implications of the

two gases stem from their origins.

Fossil natural gas is a finite, non-renewable resource extracted from

underground rock formations and coal seams, which when combusted, release

greenhouse gases into the atmosphere that would have otherwise remained

trapped underground.

Bio-SNG is recovered from gases released during the breakdown of organic

matter, making use of greenhouse gases that would have been released into the

atmosphere regardless of whether or not it was recovered and combusted.

Biogas is produced for use as a fuel in various countries, including the UK, USA,

Canada, Japan, Korea, and Germany, Europe‘s leading producer of biogas

(International Gas Union 2012). The international experience indicates that

conditions do exist for bio-SNG, and biogas more broadly, to offer a viable source

of feedstock for natural gas fuelled electricity, heating, and other applications.

Figure 5.1 presents a figure reproduced from IGU (2012, p.40) that graphically

illustrates the number of biogas production units by country.

However, despite the successful production of biogas as a source of energy

overseas, the biogas industry remains in its infancy in Australia. While small scale

biofuels project currently exist throughout Australia, there do not appear to be any

biogas projects that are comparable in scope or scale to that being considered in this

report to supply the City of Sydney.

In recent times, there has been increased interest in the potential of the biogas

industry in Australia. For example, the Australian Capital Territory Government

commissioned a pre-feasibility study of a Thermal Conversion Facility in the ACT,

which would, amongst other functions, produce biofuels using municipal waste

(URS 2010).



The Tweed Shire Council, in regional NSW, has generated electricity from biogas

since 2006, when it installed a micro power station at the Stotts Creek Recovery

Centre that is fuelled with gases recovered from the Centre‘s methane gas

extraction system. The facility can produce up to 3,000 MWh of electricity per year

(Australian Government 2012).

Introduced as part of the Australian Government‘s Clean Energy Future laws, the

Carbon Farming Initiative (CFI) provides incentives for farmers and land managers,

including municipal waste facilities to undertake activities to store carbon or reduce

greenhouse gas emissions from their land.

The CFI applies to a number of activities that are not covered by the CPM and

provides carbon credits that can be used or sold to other individuals and businesses

to offset greenhouse gas emissions. The CFI has the potential to encourage an

expansion in biogas production.

Biogas produced from sources within the Sydney Metropolitan Area or nearby

regions of NSW could be transported to the City of Sydney LGA to power the

proposed Trigeneration network and/or displace other current uses of fossil natural

gas via rail, road vehicles, or through the gas pipeline network if the gas quality is

up to bio-SNG standard.

Figure 5.1

NUMBER OF BIOGAS PRODUCTION UNITS BY COUNTRY

Source: International Gas Union (2012).



Access to the existing gas pipeline network would require the bio-SNG production

sites to be located close to the existing network, or an extension of the pipeline

network, as well as agreement with the network operators under the regulatory

framework governing gas pipelines.

The delivery method of feeding bio-SNG directly into an existing gas pipeline

network is one that currently exists overseas. In the UK, biogas producers need to

be connected to the network by licenced gas transporters, secure access agreements

with the network operators, and must meet certain gas quality standards, amongst

other regulatory requirements, in order to deliver their biogas output through the

gas pipeline network (DECC 2009).

While Australian producers would probably face similar requirements for supplying

their biogas through the gas pipeline network, at this stage, it is uncertain what

exact requirements biogas producers under the City‘s renewable energy master plan

would face under the Australian regulatory framework.

Given the infancy of the bio-SNG industry in NSW and Australia more broadly,

there are no directly comparable bio-SNG projects currently in existence that could

provide guidance as to the exact requirements that bio-SNG producers in NSW

would face in order to gain access to the gas pipeline network, apart from the

regulatory framework that currently apply to other forms of natural gas. It is likely

that the regulatory framework applying to bio-SNG would evolve with the industry.

Types of bio-SNG

The Gasification Technologies Review commissioned from Talent with Energy by

the City of Sydney in 2012 provided a detailed assessment of the renewable gas

potential associated with conversion of a range of waste and biomass feedstock

available within the region surrounding Sydney.

This study provided the City with a snapshot of the available potential in 2030 for

substitute natural gas (SNG) derived from each of the following pathways:

Syngas from Waste SNG (SNG-SfW) – SNG derived from upgrading of

synthesis gas generated from thermal conversion of residual wastes (MSW,

C&I) available within the City‘s LGA, the Sydney Metropolitan Area (SMA)

and the Extended Regulatory Area (ERA) of New South Wales;

Syngas from Biomass SNG (SNG-SfB) – SNG derived from upgrading

synthesis gas from thermal conversion of forestry and broadacre crop residues

available within a 250 km radius from the City of Sydney LGA;

Large-scale Biogas (SNG-LsB) – SNG derived from anaerobic digestion of

horticultural crops and animal manure available within a 250 km radius from

the City of Sydney LGA; and

Small-scale Biogas (SNG-SsB) – SNG derived from upgrading biogas from

anaerobic digestion of sewage sludge available at wastewater treatment plants

operating within the Sydney Metropolitan Area (SMA) and the Extended

Regulatory Area (ERA) of New South Wales;

Landfill Gas (SNG-LFG) – SNG derived from upgrading of landfill gas

generated and captured at landfills operating within a 250 km radius of the City

of Sydney LGA.



The Review provided details of the type of raw gas generated, the resulting SNG

yield and the amount of SNG delivered to the city, net of losses and own use along

delivery operations for each conversion strategy and resource stream. The study

also provided detailed feedstock resource characterization and conversion

technology assessment to enable the evaluation of the renewable energy component

within each SNG resource stream. Key findings from the study are provided in

Figure 5.2.

Figure 5.2

RENEWABLE GAS INFRASTRUCTURE – TOTAL AND RENEWABLE GAS FLOWS

Source: Reproduced from Talent with Energy (2012).

The different types of gas analysed by Talent with Energy (2012) for the City of

Sydney are condensed into four types of renewable bio-SNG for analysis in this

report, and are as follows:

SNG sourced from municipal solid waste (MSW), and commercial and

industrial (C&I) waste;

SNG sourced from biomass, such as forestry waste and broadacre crop residue;

SNG sourced from large scale biogas, such as vegetable crops and horticulture,

chicken and cattle manure; and

SNG sourced from small scale biogas, and landfill gas.



Methodology

The development of a renewable natural gas production and supply network of the

scale that would be necessary to supply the City of Sydney‘s natural gas

requirements from sources located within Sydney and in neighbouring regions has

not been accomplished in Australia to date. This would be a pioneering

achievement and make the City a leader in bio-SNG fuelled power in Australia.

However, this also presents some additional challenges to the task of evaluating the

costs of the renewable gas component of the City‘s renewable energy master plan

due to a lack of existing Australian biogas projects that could offer comparable

empirical evidence on the subject.

International experiences are of limited use as a comparator due to a number of

differences between them and Australia. For example, the climate, environment as

well as the density and distribution of population and economic activity vary

significantly between Australia and many of the countries listed in Figure 5.1, such

as Korea, Japan, the United Kingdom, and Germany.

Also, the current electricity generation technology mix is quite different between

different countries. Australia is heavily dependent on coal-fired generators for base

load electricity, and has zero nuclear power capacity. In contrast, nuclear energy

plays a significant role in the electricity production of a number of European

countries, and Japan. Furthermore, international comparisons of energy production

costs indicate that they vary greatly between countries, even when the same type of

technology is used (EPRI 2006, p.2-31).

Indeed, a paper on the potential for renewable gas in the UK by National Grid

(2009) found the cost of a range of renewable gases to be broadly comparable to

that of offshore wind technologies. As discussed later in this section, the results

from the Allen Consulting Group‘s analysis are substantially different, with

renewable gases projected to be significantly cheaper than offshore wind. Instead,

the cost of renewable gases fuelled Trigeneration is found to be broadly comparable

to that of onshore wind by 2030, but not earlier.

In order to estimate the marginal social cost of abatement of replacing grid-

electricity with electricity produced by the City of Sydney‘s proposed Trigeneration

system using bio-SNG feedstock from within Sydney and/or neighbouring regions

of NSW, the following information was required:

the availability of suitable sites for producing bio-SNG;

the volume of bio-SNG that could be produced at each site;

the emission factor of bio-SNG produced from these sites;

the levelised cost of gas (LCOG) of bio-SNG from each site;

the cost of transporting the bio-SNG from each site to the City of Sydney; and

the levelised cost of energy (LCOE) of producing electricity with the

Trigeneration network using each type of bio-SNG.

Given the dearth of biogas projects in Australia that are comparable to that

envisioned by the City of Sydney, only very limited data was available about the

likely costs of producing bio-SNG within the City of Sydney, the Greater Sydney

area, and neighbouring regions of NSW.



Similarly, little information was available about the likely costs of transporting

relatively small quantities gas from the multitude of sites that the bio-SNG would

have to be source from throughout NSW to the City. While the total volume of gas

required by the City would be substantial, they would be supplied in small

quantities from a large number of sites located throughout the Greater Sydney

region and surrounds.

The estimates reported in this section were produced using the best information

available in the public domain, and additional information provided by the City of

Sydney, including technical information sourced from a study prepared for the City

of Sydney by Talent with Energy.

Gas availability

Drawing on research conducted by Talent with Energy for the City of Sydney, a

number of sites within the Greater Sydney area and surrounding regions were

identified as being potentially suitable locations for the production of bio-SNG to

fuel the Trigeneration network.

These sites are mostly locations of existing waste collection, processing, and/or

storage sites, such as sewage treatment plants, landfill sites, and recycling centres,

which all provide ready sources of feedstock for a biogas production facility. The

exceptions are the potential sites for producing biogas from forestry, broadacre,

horticultural, and agricultural waste, which refer to centres of forestry, broadacre,

horticultural, and agricultural activity.

All of these sites are located within 250km of the City of Sydney LGA to fulfil the

City‘s requirement for locally sourced renewable energy.

The identity, capacity, and emission factor of each of these sites are set out in the

tables listed below:

Table 5.1 – SNG sourced from MSW;

Table 5.2 – SNG sourced from C&I waste;

Table 5.3 – SNG sourced from biomass;

Table 5.4 – SNG sourced from large scale biogas;

Table 5.5 – SNG sourced from small scale biogas; and

Table 5.6 – SNG sourced from landfill gas.



Table 5.1

MUNICIPAL SOLID WASTE (MSW) SNG POTENTIALS

Source Delivered (PJ/year)

Emissions Factor

(kgCO2-e/GJ)

SMA - Inner Sydney 0.82 -42.64

SMA - Northern Sydney 1.09 -42.64

SMA - Western Sydney 2.59 -42.64

SMA - Southern Sydney 0.89 -42.64

SMA - Macarthur Region 0.60 -42.61

ERA - Central Coast 0.59 -42.61

ERA - Illawarra/South 0.61 -42.61

ERA - Newcastle 1.13 -42.54

MSW Waste (All Sources) 8.32* -42.62^

^ Weighted average across all sites. * Total across all sites. Source: Unpublished estimates by Talent with Energy (2012).

Table 5.1 indicates that a total of 8.32PJ of bio-SNG produced from MSW

feedstock can potentially be sourced from MSW collection sites located across the

Sydney Metropolitan Area (SMA) and the Extended Regulatory Area (ERA) per

year. The ERA covers regions of NSW adjacent to the SMA, including the Central

Coast, Hunter and Illawarra regions. The potential annual output of gas from this

source amounts to less than a third of the City‘s 27.6 PJ per year requirement.

Table 5.2

COMMERCIAL AND INDUSTRIAL (C&I) WASTE SNG POTENTIALS


Emissions Factor

(kgCO2-e/GJ)

SMA - Inner Sydney 1.98 -28.35

SMA - Northern Sydney 2.06 -28.35

SMA - Western Sydney 4.76 -28.35

SMA - Southern Sydney 1.68 -28.35

SMA - Macarthur Region 1.09 -28.32

ERA - Central Coast 0.54 -28.32

ERA - Illawarra/South 0.56 -28.32

ERA - Newcastle 1.03 -28.35

C&I Waste (All Sources) 13.7* -28.35^




As reported in Table 5.2, a total of 13.7 PJ of bio-SNG produced from C&I

feedstock can potentially be sourced from C&I collection sites located across the

SMA and ERA per year. This amounts to just under half of the City‘s 27.6 PJ per

year requirement.

Table 5.3

BIOMASS SNG POTENTIALS


Emissions Factor

(kgCO2-e/GJ)

Oberon/Bathurst 1.14 -3.91

Mid-West 0.19 28.50

North West 0.20 28.50

West 0.66 28.50

South West 0.31 11.45

Biomass (All Sources) 2.50* 11.61^


Table 5.3 indicates that a total of 2.5 PJ of bio-SNG produced from biomass

feedstock can potentially be sourced from regions near the Greater Sydney area.

This amounts to less than 10 per cent of the City‘s projected annual requirement.



Table 5.4

LARGE SCALE BIOGAS SNG POTENTIALS

Source Delivered (PJ/year) Emissions Factor (kgCO2-e/GJ)

Fairfield and Liverpool 0.2 15.59

Blacktown 0.15 15.59

The Hills 0.04 15.59

Penrith 0.21 15.59

Camden 0.19 15.59

Cessnock, Gosford and Wyong 0.6 15.59

Hawkesbury 0.18 15.59

Wollondilly 0.3 15.59

Kiama 0.04 15.59

Wingecarribee 0.17 15.59

Lithgow 0.14 15.59

Shoalhaven 0.15 15.59

Oberon 0.21 15.59

Maitland 0.13 15.60

Singleton 0.23 15.60

Port Stephens 0.13 15.60

Bathurst 0.18 15.60

Mid-Western 0.31 32.82

Goulburn Mulwaree 0.11 15.60

Musswellbrook 0.17 32.82

Upper Lachlan 0.34 15.60

Dungog 0.31 32.82

Great Lakes 0.26 32.82

Blayney 0.28 15.60

Orange 0.03 15.60

Palerang 0.18 15.60

Upper Hunter 0.64 32.85

Boorowa 0.11 15.60

Gloucester 0.23 32.85

Cowra 0.15 15.60

Cabonne 0.24 15.60

Yass Valley 0.09 15.60

Wellington 0.1 15.60

Greater Taree 0.12 32.85

Eurobodalla 0.03 32.85

Liverpool Plains 0.08 15.61

Large Scale Biogas (All Sources) 7.03* 20.67^




As reported in Table 5.4, up to 7.03 PJ of large scale biogas can potentially be

sourced from feedstock in regions within and adjacent to the Greater Sydney area.

This amounts to just over a quarter of the City‘s projected annual requirement.

Table 5.5

SMALL SCALE BIOGAS SNG POTENTIALS


Emissions Factor

(kgCO2-e/GJ)

Bondi Sewage Treatment Plant 0.02 -37.05

Malabar Sewage Treatment Plant 0.12 -37.05

North Head Sewage Treatment Plant 0.07 -37.05

Cronulla Sewage Treatment Plant 0.03 -37.05

Warriewood Sewage Treatment Plant 0.02 -37.05

Liverpool Sewage Treatment System 0.07 -37.05

Hornsby Heights Sewage Treatment Plant 0.05 -37.05

Quakers Hill Sewage Treatment Plant 0.05 -37.05

Rouse Hill Sewage Treatment Plant 0.05 -37.05

Richmond Sewage Treatment Plant 0.03 -37.04

West Camden Sewage Treatment Plant 0.03 -37.04

Wollongong Sewage Treatment System 0.03 -37.04

Shellharbour Sewage Treatment System 0.01 -37.04

Blackheath Sewage Treatment Plant 0.01 -37.04

Norah Head Outfall – Toukley Sewage Treatment 0.02 -37.04

Gerringong-Gerroa Sewage Treatment Plant 0.00 -37.04

Belmont Wastewater Treatment Works 0.02 -37.04

Bowral Sewage Treatment Plant 0.01 -37.04

Cessnock Wastewater Treatment Works 0.01 -37.03

Burwood Beach Wastewater Treatment Works 0.02 -37.03

Farley Wastewater Treatment Works 0.01 -37.03

Raymond Terrace Wastewater Treatment Works 0.01 -37.03

Small Scale Biogas (All Sources) 0.69* -37.04^


Table 5.5 indicates that up to 0.69 PJ of small scale biogas can potentially be

produced from 22 sewage and wastewater treatment facilities located within and

adjacent to the Greater Sydney area. This amounts to 2.5 per cent of the City‘s

projected annual requirement.



Table 5.6

LANDFILL GAS SNG POTENTIALS


Emissions Factor

(kgCO2-e/GJ)

Belrose Waste and Recycling Centre 0.16 -277.74

Lucas Heights Waste and Recycling Centre 0.53 -277.37

Eastern Creek Waste and Recycling Centre 0.33 -277.58

Jacks Gully Waste and Recycling Centre 0.09 -277.81

Summerhill Waste Management Centre 0.08 -277.81

Woodlawn Landfill 0.85 -277.04

Landfill Gas (All Sources) 2.04* -277.33^


Figures reported in Table 5.6 indicate that up to 2.04 PJ of landfill gas SNG can

potentially be produced from six water collection facilities located within and

adjacent to the Greater Sydney area. This amounts to around 7 per cent of the City‘s

projected annual requirement.

It is apparent that in order to secure 27.6 PJ of bio-SNG per year from local sources,

the City of Sydney would need to source gases from dozens of sites and would

require a combination of at least three types of bio-SNG.

The implications of this fragmented supply of bio-SNG on transport and other costs

are uncertain, but it is likely that their costs would be collectively greater than that

faced by a single or small number of major gas producers.

Gas capital costs

The cost of capital for each type of gas production facility, based on an analysis of

data from Talent with Energy, is reported in Table 5.7.

Table 5.7

CAPITAL COST OF GAS PRODUCTION FACILITIES, BY TYPE (2012 DOLLARS PER

TONNE OF OUTPUT PER YEAR)

Plant Technology Resource Output Capital Cost ($/t/y)

Pyro-gasification and melting Gas from MSW 1,023

Fluid-bed gasification Gas from MSW 1,053

Plasma gasification and melting Gas from MSW 1,064

Fluid-bed gasification (biomass) Gas from Biomass 718

Large-scale Anaerobic Digestion (AD) Large-scale biogas 174

Small-scale AD Small-scale biogas 300

Landfill gas recovery Landfill gas 0.50^

^ Measured as dollars (constant 2012 prices) per normal cubic metre per year ($/Nm3/y).

Source: Allen Consulting Group analysis of unpublished estimates by Talent with Energy (2012).



Table 5.8 sets out the capital costs estimates for ancillary facilities associated with

biogas production.

Table 5.8

CAPITAL COST OF ANCILLARY PLANT AND EQUIPMENT FOR GAS PRODUCTION (2012 DOLLARS)

Facility and Equipment Purpose Unit Capital Cost

($/unit)

Syngas upgrading facility Upgrading gas to SNG standard GJ per year 15

Biogas upgrading facility Upgrading gas to SNG standard GJ per year 26

Pipeline injection station Connection to gas pipeline network GJ per year 2

Micro-LNG plant Conversion of gas to liquid natural gas for transport by road vehicle

GJ per year 37

Small (6 cubic metres) LNG tanker truck Road transport of liquid natural gas cubic metre 63,333

Small (13 cubic metres) LNG tanker truck Road transport of liquid natural gas cubic metre 43,077

Source: Allen Consulting Group analysis of unpublished estimates by Talent with Energy (2012).

Cost of gas

The cost of conventional natural gas and each type of SNG, estimated by Talent

with Energy, is reported in Table 5.9.

Table 5.9

NATURAL GAS COSTS IN 2020, BY TYPE OF GAS (REAL 2012 DOLLARS PER GJ)

Type of gas $/GJ

Conventional Natural Gas 8.6

SNG - MSW + C&I 9.7

SNG - Biomass 16.7

SNG - Large scale biogas 27.3

SNG - Small scale biogas 9.7

Source: Unpublished estimates by Talent with Energy, BREE (2012).

With the exception of conventional natural gas, the costs reported are on a levelised

cost of gas (LCOG) basis, which represents the price at which each type of gas

needs to be sold at to break even. The LCOG concept is similar to that of LCOE

used for the electricity technologies as reported in Section 3.

While the LCOG is the price at which a supplier of renewable natural gas must sell

its output in order to break even, the actual price at which the gas is sold may vary

according to market and other factors. As such, the LCOG can be considered to be

the minimum price at which each type of gas may be obtained. It is assumed that

the SNG facilities would be constructed from 2020 onwards.

The estimated price of conventional natural gas is as reported in the AETA 2012 by

BREE (2012) for 2020.



Table 5.10 sets out the availability of each SNG resource meeting the City of

Sydney‘s requirement for the gas to be ‗locally‘ sourced, that is preferably within

the City of Sydney, the Sydney Metropolitan Area, or in neighbouring regions

within NSW.

Table 5.10

SUBSTITUTE NATURAL GAS RESOURCE AVAILABILITY (PJ/YEAR)

Type of gas Maximum Availability (PJ per year)

SNG - MSW + C&I 22.0

SNG - Biomass 2.5


SNG - Small scale biogas (incl. landfill gas) 2.73

Source: Unpublished estimates by Talent with Energy.

The estimates of SNG availability were prepared for the City of Sydney by Talent

with Energy and represent estimates of the maximum amount of each gas resource

that may be obtained within the geographic boundaries set by the City. Many of

these gas resources are extracted from diverse and geographically diverse sources,

which are generally incapable of individually supplying the quantity of gas

required.

Furthermore, there is an insufficient availability of any one of these gas resource

types to meet the City‘s maximum requirement of 27.6 PJ per year.

SNG - MSW + C&I is the resource type that can be supplied in the greatest

quantity, with a maximum availability of 22.0 PJ per year. Regardless of which type

of gas is selected, it would need to be sourced in conjunction with other types of

gases to meet the 27.6 PJ requirement.

Delivered cost of gas

The delivered LCOG is the LCOG of each type of gas, plus the cost of delivering

the gas from the production site to the end user, in this case, the City of Sydney. In

modelling the LCOE of the Trigeneration system using each type of bio-SNG, the

cost of delivery or transport for fossil natural gas was adopted for all four classes of

bio-SNG.

This simplifying assumption was adopted in order to facilitate a direct comparison

of the cost implications of sourcing different types of gas, in the absence of more

detailed information about the precise location of the proposed renewable gas

facilities and the associated cost differentials.

However, this assumption may represent a lower bound estimate, as it is possible

that the bio-SNG producers examined in this report may face higher transport costs

than fossil natural gas producers due to the following reasons:

the need for the construction of additional pipelines, equipment, and associated

capital works to link up the bio-SNG sites to the gas pipeline network;



additional capital works to ensure that the quality of the bio-SNG meets the

standards required by the pipeline operators, which would probably use fossil

natural gas quality levels as the standard, given the dominance of fossil natural

gas in the Australian market; and

the relatively small scale of each of the individual bio-SNG sites, relative to

traditional fossil natural gas producers.

Estimates of the delivery cost associated with using two different delivery methods

over a range of distances are reported in Appendix D to facilitate the consideration

of a wider range of delivery cost possibilities.

Delivered cost of electricity

Using the delivered LCOG of each type of bio-SNG, it is possible to calculate the

LCOE of producing electricity from the City‘s proposed 372MW Trigeneration

capacity.

The estimated delivered cost of electricity can then be calculated through the

addition of the estimated cost of delivering electricity from the Trigeneration

system to the end user to the LCOE.

The delivered cost of each type of Trigeneration generation is calculated by:

taking the delivered cost estimated for Trigeneration in Section 4, which

assumed the use of fossil natural gas as its feedstock, and recalculating the gas

price component with the delivered LCOG of each bio-SNG;

adjusting for the impact of the CPM on the delivered cost of electricity due to

the different emission factor of each type bio-SNG and fossil natural gas; and

adjusting for the impact of the RET on the delivered cost of electricity due to

the different emission factors of each type of natural gas.

Table 5.11 sets out the estimated delivered cost of electricity generated by the

City‘s 372MW Trigeneration network using each of the four types of bio-SNG.

Table 5.11

DELIVERED COST OF ELECTRICITY IN 2020 - TRIGENERATION WITH BIO-SNG, REAL

2012 DOLLARS PER MEGAWATT HOUR OF GENERATION ($/MWH)

Trigeneration with Renewable Gases $/MWh

Trigeneration (SNG - MSW + C&I) 215

Trigeneration (SNG - Biomass) 216

Trigeneration (SNG - Large scale biogas) 221

Trigeneration (SNG - Small scale biogas) 214


With the delivered cost of electricity calculated, the marginal social cost of

abatement of Trigeneration electricity generated using bio-SNG can then be

combined with emission factor data and an analysis of the baseline electricity

generation technology of coal-fired electricity to determine the marginal social cost

of abatement of each of these Trigeneration fuel options.




The marginal social cost of abatement under the Central scenario at 2020, 2025, and

2030 are presented over the remainder of this section. Black coal without CCS is

the baseline technology used for this analysis.

The marginal social cost of abatement has been estimated by adjusting the estimates

of the cost of the City‘s 372MW Trigeneration network produced by Kinesis (2012)

for the City of Sydney. The natural gas cost share of the costs is adjusted to reflect

the costs of different gas resource options.

Further adjustments are made to account for the influence of the CPM and RET as

well as inflation since the Kinesis analysis was conducted.

The marginal social cost of abatement results reported for each year represents the

relative costs of adopting each type of technology in that particular year. Electricity

supplied from the same type of technology installed in earlier years will have a cost

that is associated with the year it was installed, not the present year.

The exception is for the Trigeneration technologies. It is assumed that construction

of the Trigeneration network begins in 2013, and that the renewable gas resources

extraction capacity would be installed at selected sites from 2020 onwards.

Note that the estimates for Trigeneration (Natural Gas) are based on the figures

reported in the Trigeneration Master Plan and adjusted for 2012 prices to provide a

common base of comparison.

In addition, note that none of the SNGs are expected to be capable of supplying

sufficient gas to power the Trigeneration network. If any of the SNG options are

selected, their cost would need to be considered in conjunction with the cost of

other gas sources that would be needed to supply the full 27.6 PJ requirement of the

City. This could range from conventional natural gas to any of the other SNGs.

The analysis of the implication of the Trigeneration system being supplied by

several different types of natural gas resources and/or from multiple suppliers of

SNGs have not been undertaken for this report. However, the sourcing of gas from

multiple suppliers is likely to have different cost implications relative to receiving a

supply of gas from a single source.

Furthermore, the potential for the use of the renewable SNGs in alternative

applications, such as in CCGT plants, or for heating, and the implications such

applications may have for the market prices of these gases has not been factored

into this analysis.

However, such additional demand for renewable SNGs would be expected to affect

the costs faced by the Trigeneration network for these resources.

Figure 5.3 presents the marginal social cost of abatement of each of the renewable

electricity technologies that are available by 2020, including the four renewable gas

fuelled Trigeneration options, and a number of comparator technologies:

the City of Sydney‘s Trigeneration master plan; and

Combined Cycle Gas Turbine (CCGT).



Figure 5.3




As in the analysis in Section 4, geothermal electric is not expected to be available

by 2020. Two additional comparator technologies also not yet available at this point

in time are:

CCGT with carbon capture and storage (CCS); and

black coal with CCS.

This analysis indicates that micro wind, Trigeneration (SNG – MSW + C&I), and

Trigeneration (SNG – Small scale biogas) could potentially have negative marginal

social costs of abatement by 2020.



Figure 5.4 presents the marginal social cost of abatement by 2025. All technologies

are available by 2025, with building solar PV and micro wind estimated to

potentially join the group of technologies with negative abatement costs.

Figure 5.4






Estimates of the marginal social cost of abatement by 2030 are presented in

Figure 5.5. At this time, large scale onshore wind technology is also estimated to

potentially have negative marginal social costs of abatement.

Figure 5.5




Evaluation of renewable electricity options

Based on the assumptions of a medium carbon price path along with the associated

macroeconomic and policy environment, it is projected that a small number of

technologies could potentially offer renewable electricity alternatives to coal-fired

electricity at a zero or negative marginal social cost of abatement by 2030. All other

technologies are not expected to be viable on average if left to market forces alone

without additional subsidies or other incentives supplied to cover the cost

differential with baseline grid sourced electricity.



Trigeneration (SNG–MSW+C&I), Trigeneration (SNG–Small scale biogas),

building solar PV, building micro wind, and onshore wind are the renewable

electricity options that are potentially viable without additional incentives.

It is important to note that while a number of different renewable and low-emission

energy technology options have been estimated as potentially having low or even

negative marginal social costs of abatement by 2030, it is not possible to completely

source the City‘s electricity requirements from any one of these sources, as they are

generally subject to capacity constraints. In particular, the building and precinct

scale technologies are limited by the amount of space available in the City to host

the necessary equipment.

The renewable gas resources are also constrained by limits on their availability. The

gas will need to be sourced from dozens of different sites across the Sydney

Metropolitan Area and neighbouring regions. While it may be potentially

economically viable to use these particular sources of renewable gases as fuel for

the Trigeneration network, it is unclear if it would be commercially viable. The

costs and complexities of sourcing small quantities of gas from dozens of sites

across NSW may render a number of renewable gas resource options impractical.



Section 6

Conclusion

As part of its Decentralised Energy Master Plan – Renewable Energy, the City of

Sydney aims to supply 30 per cent of its electricity needs with local renewable

energy, displacing around 1.3 TWh of grid electricity, and replacing up to 27.6 PJ

of fossil natural gas with renewable gas resources, by 2030.

This report has examined the potential economic viability of a number of renewable

energy technology and resource options being considered by the City as possible

sources of renewable power to achieve the targets of its plan, under three distinct

scenarios of the world to 2030, reflecting different possible developments of the

economic, policy, energy, and carbon market environments. Specifically, this report

has set out estimates of:

the capital costs for each of the 14 renewable electricity technologies and four

renewable gas resources to be considered for inclusion into the City‘s

renewable electricity capacity by 2030 (Section 3 of this report);

a marginal social cost of abatement curves for three scenarios for all 14

renewable electricity technologies (Section 4 of this report); and

an additional marginal social cost of abatement curve including estimates for

the City‘s proposed Trigeneration network using each of the four renewable gas

resources as fuel (Section 5 of this report).

The methodology for undertaking this study, as set out in Section 2, is in line with

that previously used to undertake the financial and economic analysis of the City‘s

Trigeneration Master Plan by the Allen Consulting Group in conjunction with

Kinesis in 2012. Assumptions are also provided in greater detail in

Appendixes A to D of this report.














accounted for;













different macroeconomic, industry, and policy environment scenarios.




Table 6.1 provides a summary of the potential marginal social cost of abatement

estimated for each type of technology in real 2012 dollars per tonne of carbon

dioxide equivalents abated under the Central scenario.

Table 6.1

SUMMARY, CENTRAL SCENARIO - MARGINAL SOCIAL COST OF ABATEMENT

(REAL 2012 DOLLARS PER TONNE OF CARBON DIOXIDE EQUIVALENTS)

Technology 2020 2025 2030

Solar hot water (Building) 67 41 26

Solar PV (Building) 23 -28 -65

Micro wind (Building) -17 -40 -53

Wind turbines (Precinct) 43 37 34

Direct use geothermal (Precinct) 49 37 26

Concentrating solar thermal (Precinct) 100 71 60

Onshore wind 19 9 -4

Offshore wind 113 106 90

Geothermal electric N/A 142 127

Concentrating solar PV 88 69 47

Concentrating solar thermal 175 141 129

Wave 247 150 133

Tidal 281 185 171

Hydro 126 121 117

Trigeneration (Natural Gas) 27 27 27

Black Coal with CCS N/A 96 80

CCGT with CCS N/A 57 41

CCGT 85 83 69

Trigeneration (SNG - MSW + C&I) 0 0 0

Trigeneration (SNG - Biomass) 1 1 1

Trigeneration (SNG - Large scale biogas) 5 5 5

Trigeneration (SNG - Small scale biogas) -2 -2 -2




This scenario is based on the Government Policy carbon price trajectory as

modelled in the September 2011 update to the Australian Treasury‘s 2011 Strong

Growth, Low Pollution: Modelling a Carbon Price report.

Based on the assumptions of a medium carbon price path along with the associated

macroeconomic and policy environment, it is projected that a small number of

technologies could potentially offer renewable electricity alternatives to coal-fired

electricity at a zero or negative marginal social cost of abatement by 2030. All other

technologies are not expected to be viable on average if left to market forces alone

without additional subsidies or other incentives supplied to cover the cost

differential with baseline grid sourced electricity.

Trigeneration (SNG – MSW+C&I), Trigeneration (SNG – Small scale biogas),

building solar PV, building micro wind, and onshore wind are the renewable

electricity options that are potentially viable without additional incentives.

It is important to note that while a number of different renewable and low-emission

energy technology options have been estimated as potentially having low or even

negative marginal social costs of abatement by 2030, it is not possible to completely

source the City‘s electricity requirements from any one of these sources, as they are

generally subject to capacity constraints. In particular, the building and precinct

scale technologies are limited by the amount of space available in the City to host

the necessary equipment.

The renewable gas resources are also constrained by limits on their availability. The

gas will need to be sourced from dozens of different sites across the Sydney

Metropolitan Area and neighbouring regions. While it may be potentially

economically viable to use these particular sources of renewable gases as fuel for

the Trigeneration network, it is unclear if it would be commercially viable. The

costs and complexities of sourcing small quantities of gas from dozens of sites

across NSW may render a number of renewable gas resource options impractical.

Overall, a number of renewable electricity technologies have been found to have

the potential to provide a low to zero emissions alternative to grid electricity for the

City of Sydney by 2030 at zero additional or even at a lower cost under certain

macroeconomic, industry and policy environments as set out under the three

scenarios, on average. There are also a small number of options that can potentially

become viable with a small subsidy in addition to the existing federal and state

schemes supporting the renewable electricity sector.

However, as these results are produced for an average generating unit of each

technology type, and do not account for site and project specific factors, these

results should be interpreted as an indication of the potential relative viability of

each technology. Project specific analysis should be undertaken before making

decisions about individual renewable energy projects.



Appendix A

Economic assumptions

Overview

The methodology underlying the Renewable Energy Opportunities for Sydney

analysis is based on that of the Australian Energy Technology Assessment (AETA)

2012 by the Bureau of Resources and Energy Economics. The AETA 2012 is the

best, most up to date and comprehensive estimate of the cost of electricity

generation technologies available in the public domain.

The economic assumptions of the Central scenario of this analysis is consistent with

that of AETA, which are in turn consistent with those of the National Transmission

Network Development Plan of the Australian Energy Market Operator (AEMO)

and the Strong Growth, Low Pollution: Modelling a Carbon Price (SGLP) report

by the Australian Department of the Treasury.

The NTNDP is published by AEMO to provide comprehensive information to the

energy industry to support the development of planning for the electricity

transmission network across Australia.

The SGLP report was published and updated by the Australian Treasury in 2011

and represents the most comprehensive modelling available on the economic

impacts of the introduction of carbon pricing to Australia, including impacts on the

energy sector.

Macroeconomic assumptions

The macroeconomic assumptions underlying the Central scenario is based on those

of AETA 2012, which incorporate elements of the ‗Government Policy‘ scenario of

the SGLP report and the ‗Planning‘ scenario of the NTNDP. The Central scenario

represents a possible path that the Australian economy would take from the present

to 2050 in a world where the Australian Government‘s Clean Energy Laws are in

effect, with the carbon price path following the ‗Government Policy‘ scenario.

Figure A.1 is a copy of the macroeconomic assumptions table from AETA 2012,

which has been adopted as the macroeconomic assumptions for this analysis.



Figure A.1

MACROECONOMIC ASSUMPTIONS OF AETA 2012

Source: BREE (2012).

The High scenario is based on the ‗High Price‘ scenario of the SGLP report while

the Low scenario is based on a scenario developed for this analysis where the

carbon price does not increase rapidly at the end of the fixed price period in 2015.

Figure A.2 illustrates the carbon price paths underlying the three scenarios.



Figure A.2

CARBON PRICE PATHS BY SCENARIO (REAL 2012 DOLLARS PER TONNE OF CO2 EQUIVALENT EMISSIONS,

2012$/TCO2-E)

Source: Allen Consulting Group calculations, Department of the Treasury (2011).

Retail electricity prices under each scenario are presented in Figure A.3.

Forecasts of future Australian energy prices are central to the analysis of this report.

Deviations from the forecast prices underlying the economic scenarios framing this

analysis will substantially alter the implications of this report. While the electricity

and gas prices used to develop the macroeconomic scenarios underlying this report

is based on reputable publicly available sources of information such as the BREE‘s

AETA 2012 and the Australian Treasury‘s 2011 SGLP report, these variables will

fluctuate with broader changes to the Australian and international energy markets.

Critically, global demand will have impacts on Australian gas and other energy

prices, with domestic prices rising and falling dependent on international price

movements. The development of the coal seam gas industry and the exploitation of

other emerging sources of energy in Australia and overseas are expected to have a

major impact on the international and domestic price of energy. This will have

immense impacts on the results of the analysis conducted for this report. However,

at this stage, it remains difficult to confidently assess the extent and direction of the

net impacts that domestic and international developments in energy supply and

demand will have on future energy prices.



The exchange rate will have a major impact on the domestic prices of energy, while

global demand for Australian energy commodities, such as coal and gas, will in turn

have impacts on the Australian exchange rate. Exchange rate fluctuations will also

have impacts on the capital cost of Australian energy projects, since many key

components of electricity generators such as turbines and solar panels are sourced

from overseas suppliers.

However, any predictions about future exchange rate movements and other

macroeconomic variables, especially those extending 40 years into the future, are

almost certain to deviate from reality. The results presented in this report should be

interpreted as an estimate of possible future outcomes given a particular set of

macroeconomic assumptions.

Figure A.3

RETAIL ELECTRICITY PRICES BY SCENARIO (REAL 2012 DOLLARS PER MEGAWATT HOUR, 2012$/MWH)

Source: Allen Consulting Group calculations, Department of the Treasury (2011).

Policy framework assumptions

The policy framework relating to the renewable energy sector that is in place as of

the time of writing is assumed to remain in place unchanged until 2030. Deviations

in the policy framework from its current settings and design would have significant

impacts on the implications of the analysis contained in this report. While all care

has been taken to incorporate realistic assumptions about future developments in

the policy framework, government policy decisions are by its nature unpredictable.



Several major energy and renewable energy policies are discussed in detail in this

section. However, in general, state renewable energy schemes are generally

expected to be wound down with the introduction of the Australian Government‘s

CPM and associated Clean Energy Future policies in 2012. However, the

NSW Government‘s feed in tariff policy is expected to be revived and remain in

operation for the duration of the study‘s timeframe.

As discussed in Section 2 of the report, details of the new feed in tariff regime in

NSW to replace the previous scheme that was closed to new entrants by the NSW

Government in 2011 have not yet been finalised.

The feed in tariff scheme assumed to operate in NSW for the purposes of this

analysis is based on the Independent Pricing and Regulatory Tribunal (IPART)

determination on ‗a fair and reasonable solar feed-in tariff for NSW‘ of June 2012.

The Carbon Pricing Mechanism (CPM)

The Australian Government‘s CPM came into effect on 1 July 2012. It is designed

to operate in a fixed price period for the first three years, where the CPM permit

price is mandated by the Government, with a flexible price trading period to follow.

Since then, the scheme design has already been revised, with the original floor price

set for the flexible price trading period repealed in late 2012 following the

announcement that the CPM will be linked to the European Union Emissions

Trading Scheme (EU ETS) at the conclusion of the fixed price period.

The effects of the EU ETS linkage on CPM permit prices are uncertain. However,

these changes to the CPM policy is likely to result in actual permit prices that are

significantly different from those modelled by the Australian Treasury in its 2011

SGLP report and subsequent update, released in September 2011, which are the

basis for the carbon price trajectories underlying the macroeconomic scenarios

constructed for this study.

Furthermore, the fate of the CPM remains uncertain, with a Federal election to be

held in September 2013, and the Coalition Opposition‘s stated intent to repeal the

CPM and associated policies if it is elected to office. The repeal of or substantial

changes to the design of the CPM and associated policies are likely to result in

substantial changes to the implications of this study. While the Coalition has

proposed alternate climate change mitigation policies, it is currently unclear what

their impact on the price of electricity and energy will be.

The Renewable Energy Target (RET)

The future of the Renewable Energy Target, which is due to expire in 2030, is

currently unknown, but is assumed to continue until at least 2030 as in the

Australian Treasury‘s 2011 SGLP report and associated consultant reports.

However, if a decision is made to not continue the RET beyond 2030, it is expected

that this would have a negative impact on the RET‘s LGC and STC prices in the

years preceding the termination of the scheme. The value of the certificates

associated with the RET is likely to plunge well before 2030 if it is expected to

become worthless by that year.



In any case, the design of the RET is also assumed to not change between the

present and 2030. However, given the revisions to the scheme that has taken place

between its inception as the Mandatory Renewable Energy Target (MRET) in

2001and the present, it is entirely possible that there may be further changes to the

scheme in the future.

In 2009, the target of the RET was raised from 9,500 GWh to 45,000 GWh by 2020

under the Expanded Renewable Energy Target policy. The scheme was further

amended in 2010 with the introduction of the Enhanced Renewable Targe Policy,

which separated the RET into two parts: the Small-scale Renewable Energy

Scheme (SRES), and the Large-scale Renewable Energy Target (LRET). This

change replaced the Renewable Energy Certificate (REC) under the RET with the

Small-scale Technology Certificate (STC), and the Large-scale Generation

Certificate (LGC), respectively. REC is now used as an umbrella term covering

both types of certificates.

REC prices interact with the CPM permit prices, and given the great uncertainties

associated with future movements in CPM prices and indeed the future existence of

the CPM, as discussed in the section about the CPM, it is difficult to accurately

forecast the future trajectory of REC prices.



Appendix B

Cost assumptions

Overview

Assumptions underlying the cost estimates in the analysis are based on those in the

AETA 2012. Where available, cost estimates from AETA 2012 were used to

calculate the delivered cost for this analysis. However, for technologies not covered

by AETA 2012, such as the building scale technologies, costs were estimated using

a consistent methodology.

Note that the cost estimates represent the average or ‗typical‘ cost associated with a

constructing and operating a ‗typical‘ generating unit of each type of technology in

NSW. The actual costs of constructing a generation facility in the Greater Sydney

region and/or nearby regions of NSW would vary according to site and project

specific factors, and may be above or below the average. Scale and location are

major determinants of the size of the variation of cost from the average.

Cost assumptions

AETA 2012 assumptions regarding each cost element that have been adopted for

this study are outlined below.

Note that the building scale solar hot water and precinct-scale direct use geothermal

technologies differ from the other technologies in that they do not directly generate

renewable electricity. Instead solar hot water systems produces renewable energy to

heat water, while direct use geothermal systems uses renewable energy to directly

heat and cool buildings. The two technologies displace the use of emissions

intensive grid electricity for water and building heating with renewable energy.

As such the costs reported for these technologies should be interpreted as the cost of

displacing a megawatt hour of grid electricity, rather than as the cost of generating a

megawatt hour of renewable electricity.

Direct and Indirect Capital Costs

The capital cost estimates for each technology include direct and indirect cost

components. AETA 2012 (BREE 2012, p.14) excludes the following from direct

and indirect costs:

escalation through the period of performance;

taxes;

site specific considerations;

for carbon capture and storage (CCS) technologies, the cost associated with

carbon dioxide injection wells, pipelines to transport the captured emissions to

a storage site, and other costs associated with the storage facility;

import tariffs that may be charged for imported equipment or shipping charges

for the equipment; and

interest during construction (IDC) and financing costs.



Decommissioning Costs

Costs associated with plant decommissioning are not included in LCOE

calculations.

Estimated Scope

Cost estimates relate to a complete power plant on a generic site. Site-specific

considerations such as soil conditions, seismic zone requirements, accessibility, and

local regulatory requirements are not considered in the cost estimates (BREE 2012,

p.14).



Appendix C

Electricity technology assumptions

Overview

The technical specifications of each electricity technology evaluated in this report

are adopted from the AETA 2012 publication where available. For technologies not

included in AETA 2012, the technical specifications were based on public domain

information about the particular technologies and assessed on a basis consistent

with AETA 2012.

Technical specifications

As part of the process of assessing each renewable electricity technology,

assumptions were made about a number of characteristics of a typical generating

unit. These characteristics include:

Plant capacity: measured in megawatts, this is the nameplate capacity of a

typical generating unit using the particular technology. This is the output of the

plant if it was operating at full capacity at all times.

Plant capacity factor: the ratio of the actual output of a power plant over a

given period of time and its potential output if it had operated at full nameplate

capacity the entire time.

Thermal efficiency: the ratio between the energy used to fuel a power plant and

the plant‘s energy output.

Auxiliary load: also known as the internal or parasitic load, this is the amount of

electricity from the plant‘s output that is required to sustain the plant‘s

operations.

Emissions: this is the amount of greenhouse gases that are emitted by the plant

in the production of its energy output.

Emissions captured: this is the percentage of greenhouse gas emissions from a

plant that is captured using carbon capture and storage technology.

First year: the year when the technology first becomes available for use in

electricity generation on a commercial scale.

Life of plant: the amortisation period of the plant, the useful life of the plant

without further upgrades and refurbishments. It can be thought of as the period

over which a plant must achieve its economic return.

Where available, the assumptions adopted for this report are as published in the

AETA 2012 (BREE 2012). The assumptions for the remaining technologies were

developed by the Allen Consulting Group in a manner consistent with AETA 2012

using information that is available in the public domain.

Actual power plants utilising each technology will likely possess characteristics that

are different from those specified in this report. The characteristics assumed in the

report represent a typical or average plant for each technology.



The technical assumptions for the renewable electricity technologies and a number

of additional baseline comparator technologies are reported in Table C.1. The

comparator technologies include black coal with carbon capture and storage (CCS),

combined cycle gas turbine (CCGT) with and without CCS, and the local

trigeneration capacity to be installed as part of the City‘s Decentralised Energy

Master Plan - Trigeneration.

Table C.1

TECHNICAL ASSUMPTIONS - BUILDING AND PRECINCT SCALE RENEWABLE ELECTRICITY TECHNOLOGIES

Plant Capacity

(MW)

Plant Capacity

Factor (%)

Thermal Efficiency (HHV) (%)

Auxiliary Load (MW)

Emissions (kgCO2e/ MWh)

Emissions

captured (%)

First Year

Life of plant (years)

Building integrated renewable electricity technology within LGA

Solar hot water 0.002 16 - 0 217 0 2012 20

Solar PV 0.002 14 - 0 0 - 2012 20

Micro wind 0.003 25 - 0 0 - 2012 25

Precinct scale renewable electricity technology within LGA

Wind turbines 2 20 - 0 0 - 2012 30


10 22 - 0 0 - 2012 20

Concentrating solar thermal

18 42 - 2 0 - 2012 30

Large scale renewable electricity technology beyond the LGA

Onshore wind 100 38 - 0.5 0 - 2012 30

Offshore wind 100 40 - 0.5 0 - 2012 30

Geothermal electric

10 83 - 1 0 - 2025 30

Concentrating solar PV

100 24 - 0 0 - 2012 30

Concentrating solar thermal

138 23 - 12 0 - 2012 30

Wave 20 35 - 0 0 - 2020 30

Tidal 20 35 - 0 0 - 2020 30

Hydro 20 20 - 0 0 - 2012 10

Source: BREE (2012), and Allen Consulting Group analysis. Note: ^ Assuming the use of conventional non-renewable natural gas as feedstock.



Appendix D

Renewable gas resources assumptions

Overview

The renewable gas resources assumptions are formulated based on research

conducted for the City of Sydney by Talent with Energy.

The LCOG at which each type of gas resource can be made available and the

quantities of each type of gas resource that can be made available are provided in

Table D.1 and D.2, respectively.

Note that 1 petajoule (PJ) is equal to 1 000 000 gigajoules (GJ).

Table D.1

AVERAGE SUBSTITUTE NATURAL GAS COSTS, BY TYPE OF GAS (REAL 2012

DOLLARS PER GJ)

Type of gas $/GJ

SNG - MSW + C&I 9.7

SNG - Biomass 16.7



Source: Allen Consulting Group calculations (2013) based on unpublished estimates by Talent with Energy (2012).

Table D.2

AVERAGE SUBSTITUTE NATURAL GAS RESOURCE AVAILABILITY (PJ/YEAR)

Type of gas Maximum Availability (PJ per year)

SNG - MSW + C&I 22.0

SNG - Biomass 2.5



Source: Allen Consulting Group calculations (2013) based on unpublished estimates by Talent with Energy (2012).



Detailed SNG data

Detailed SNG potentials data by type of gas calculated by the Allen Consulting

Group for this study using data prepared by Talent with Energy for the City of

Sydney are presented in the following tables. All reported LCOGs are for gas

produced from facilities built in 2020. All prices are expressed in real 2012 dollars.

Table D.3

LANDFILL GAS SNG POTENTIALS

Source LCOG ($/GJ)

Delivered (PJ/year)

Emissions Factor

(kgCO2-e/GJ)

Belrose Waste and Recycling Centre 10.54 0.16 -277.74

Lucas Heights Waste and Recycling Centre

10.54 0.53 -277.37

Eastern Creek Waste and Recycling Centre

10.54 0.33 -277.58

Jacks Gully Waste and Recycling Centre 10.55 0.09 -277.81

Summerhill Waste Management Centre 10.55 0.08 -277.81

Woodlawn Landfill 10.55 0.85 -277.04

Landfill Gas (All Sources) 10.55^ 2.04* -277.33^

Source: Allen Consulting Group calculations based on unpublished estimates by Talent with Energy (2012). Note: ^ Weighted average across all sites. * Total across all sites.

Table D.4

BIOMASS SNG POTENTIALS

Source LCOG ($/GJ)

Delivered (PJ/year)

Emissions Factor

(kgCO2-e/GJ)

Oberon/Bathurst 14.29 1.14 -3.91

Mid-West 20.58 0.19 28.50

North West 20.58 0.20 28.50

West 20.58 0.66 28.50

South West 12.27 0.31 11.45

Biomass (All Sources) 16.68^ 2.50* 11.61^




Table D.5

SMALL SCALE BIOGAS SNG POTENTIALS

Source LCOG ($/GJ)

Delivered (PJ/year)

Emissions Factor

(kgCO2-e/GJ)

Bondi Sewage Treatment Plant 7.28 0.02 -37.05

Malabar Sewage Treatment Plant 7.28 0.12 -37.05

North Head Sewage Treatment Plant 7.28 0.07 -37.05

Cronulla 7.28 0.03 -37.05

Warriewood 7.28 0.02 -37.05

Liverpool 7.28 0.07 -37.05

Hornsby Heights 7.28 0.05 -37.05

Quakers Hill 7.28 0.05 -37.05

Rouse Hill 7.28 0.05 -37.05

Richmond 7.28 0.03 -37.04

West Camden 7.28 0.03 -37.04

Wollongong 7.28 0.03 -37.04

Shellharbour 7.28 0.01 -37.04

Blackheath 7.28 0.01 -37.04

Norah Head Outfall - Toukley 7.28 0.02 -37.04

Gerringong-Gerroa 7.28 0.00 -37.04

Belmont Wastewater Treatement Works 7.28 0.02 -37.04

Bowral 7.28 0.01 -37.04

Cessnowck 7.28 0.01 -37.03

Burwood Beach 7.28 0.02 -37.03

Farley 7.28 0.01 -37.03

Raymond Terrace 7.28 0.01 -37.03

Small Scale Biogas (All Sources) 7.28^ 0.69* -37.04^




Table D.6

COMMERCIAL AND INDUSTRIAL (C&I) WASTE SNG POTENTIALS

Source LCOG ($/GJ)

Delivered (PJ/year)

Emissions Factor

(kgCO2-e/GJ)

SMA - Inner Sydney 8.87 1.98 -28.35

SMA - Northern Sydney 8.87 2.06 -28.35

SMA - Western Sydney 8.87 4.76 -28.35

SMA - Southern Sydney 8.87 1.68 -28.35

SMA - Macarthur Region 8.87 1.09 -28.32

ERA - Central Coast 8.87 0.54 -28.32

ERA - Illawarra/South 8.87 0.56 -28.32

ERA - Newcastle 8.88 1.03 -28.35

C&I Waste (All Sources) 8.87^ 13.7* -28.35^


Table D.7

MUNICIPAL SOLID WASTE (MSW) SNG POTENTIALS

Source LCOG ($/GJ)

Delivered (PJ/year)

Emissions Factor

(kgCO2-e/GJ)

SMA - Inner Sydney 11.08 0.82 -42.64

SMA - Northern Sydney 11.08 1.09 -42.64

SMA - Western Sydney 11.08 2.59 -42.64

SMA - Southern Sydney 11.08 0.89 -42.64

SMA - Macarthur Region 11.08 0.60 -42.61

ERA - Central Coast 11.08 0.59 -42.61

ERA - Illawarra/South 11.08 0.61 -42.61

ERA - Newcastle 11.09 1.13 -42.54

MSW Waste (All Sources) 11.08^ 8.32* -42.62^




Table D.8

LARGE SCALE BIOGAS SNG POTENTIALS

Source LCOG ($/GJ) Delivered (PJ/year) Emissions Factor (kgCO2-e/GJ)

Fairfield 30.05 0.06 15.59

Blacktown 15.10 0.15 15.59

Liverpool 13.80 0.14 15.59

The Hills 18.79 0.04 15.59

Penrith 18.67 0.21 15.59

Camden 15.11 0.19 15.59

Gosford 12.65 0.44 15.59

Hawkesbury 30.71 0.18 15.59

Wyong 15.20 0.11 15.59

Wollondilly 17.45 0.3 15.59

Kiama 29.68 0.04 15.59

Wingebarribee 18.83 0.17 15.59

Cessnock 24.05 0.05 15.59

Lithgow 29.68 0.14 15.59

Shoalhaven 29.67 0.15 15.59

Oberon 29.83 0.21 15.59

Maitland 17.31 0.13 15.60

Singleton 28.94 0.23 15.60

Port Stephens 17.62 0.13 15.60

Bathurst 29.79 0.18 15.60

Mid-Western 37.98 0.31 32.82

Goulburn Mulwaree 26.96 0.11 15.60

Musswellbrook 37.98 0.17 32.82

Upper Lachlan 27.43 0.34 15.60

Dungog 32.52 0.31 32.82

Great Lakes 26.80 0.26 32.82

Blayney 29.69 0.28 15.60

Orange 29.71 0.03 15.60

Palerang 29.63 0.18 15.60

Upper Hunter 37.92 0.64 32.85

Boorowa 29.69 0.11 15.60

Gloucester 37.99 0.23 32.85

Cowra 29.67 0.15 15.60

Cabonne 29.39 0.24 15.60

Yass Valley 29.67 0.09 15.60

Wellington 29.37 0.1 15.60

Greater Taree 37.20 0.12 32.85

Eurobodalla 37.98 0.03 32.85

Liverpool Plains 29.65 0.08 15.61

Source: Allen Consulting Group calculations based on unpublished estimates by Talent with Energy (2012).



Levelised Cost of Gas

The methodology used by Talent with Energy to calculate the LCOG of each

renewable gas is set out below.

Methodology

The levelized cost of gas (LCOG), calculated as the present worth of revenue

requirements divided by the net amount of energy supplied at the point of delivery,

represents the minimum selling price for the substitute natural gas that will meet the

revenue requirements (including the total of capital and operating costs across the

entire generation and delivery chain, as well as the required return on investment)

over the project lifetime.

Assuming a project with constant energy outputs and costs over its lifetime, the

levelized cost of gas (LCOG) is calculated as follows:

where:

is the equivalent annual worth3

of total capital investment over the

project lifetime, expressed in AUD/y;

is the annual O&M expenditure, expressed in AUD/y; and

is the annual gas delivered to consumers, net of own consumption,

conversion, upgrading and delivery losses.

Gas cost assumptions

The cost assumptions underlying the unpublished study prepared by Talent with

Energy for the City of Sydney are set out below.

Equipment cost estimates

Capacity function cost estimates

Figure D.1 below provides a summary of capacity cost function estimates adopted

for this study, with details of the reference facility size adopted for each pathway.

3

Derived by multiplying the total capital cost by an appropriate annualization factor, such as the capital recovery

factor (CRF), integrating parameters such as the discount rate and project lifetime.



Figure D.1

TALENT WITH ENERGY COST ASSUMPTIONS: RENEWABLE GAS INFRASTRUCTURE – CAPACITY COST FUNCTION

ESTIMATES FOR MAJOR EQUIPMENT

Source: Supplied by Talent with Energy (2012).



Equipment cost factor estimates

Figure D.2 provides a summary of major equipment cost factors adopted for this

study.

Figure D.2

TALENT WITH ENERGY COST ASSUMPTIONS: RENEWABLE GAS INFRASTRUCTURE – MAJOR EQUIPMENT COST

FACTORS


Feedstock, fuel and utilities costs

Figure D.3 provides a summary of feedstock, fuel and utilities cost assumptions

adopted for this study.

Negative feedstock cost figures indicate the waste management fee paid at the plant

gate, net of transportation cost, by resource owners delivering their waste to the

plant.



Figure D.3

TALENT WITH ENERGY COST ASSUMPTIONS: RENEWABLE GAS INFRASTRUCTURE – FEEDSTOCK, FUEL AND

UTILITIES COSTS


Financial assumptions

The financial assumptions underlying the unpublished study prepared by Talent

with Energy for the City of Sydney are set out below.

Figure D.4

COST ASSUMPTIONS: RENEWABLE GAS INFRASTRUCTURE – FEEDSTOCK, FUEL AND UTILITIES COSTS




Delivery cost assumptions

Talent with Energy examined the possible costs of transporting renewable gases to

the City of Sydney from production sites up to 250km away, using two different

methods of delivery:

direct injection into the natural gas pipeline network, which would require the

upgrading of the gas to pipeline quality SNG standard; and

road transport, which would require the conversion of the gases into liquid

natural gas form for carriage in tanker vehicles.

The delivery costs would be added onto the LCOG of each gas to work out a

delivered LCOG for each type of renewable gas.

Pipeline

For this delivery pathway we consider a reference gas injection facility of 100,000

GJHHV/y.

The figures below summarize the technical characteristics, capital costs, operating,

and levelised costs for this infrastructure, considering the indicative delivery

distances of 50, 100, 150, 200 and 250 km.

Figure D.5

TALENT WITH ENERGY ASSUMPTIONS: RENEWABLE GAS INFRASTRUCTURE – PIPELINE DELIVERY TECHNICAL

CHARACTERISTICS




Figure D.6

TALENT WITH ENERGY COST ASSUMPTIONS: RENEWABLE GAS INFRASTRUCTURE – PIPELINE DELIVERY CAPITAL

COSTS


Figure D.7

TALENT WITH ENERGY COST ASSUMPTIONS: RENEWABLE GAS INFRASTRUCTURE – PIPELINE DELIVERY

OPERATING COSTS




Figure D.8

TALENT WITH ENERGY COST ASSUMPTIONS: RENEWABLE GAS INFRASTRUCTURE – PIPELINE DELIVERY

LEVELISED COSTS


Road transport

For this delivery pathway we consider a reference liquefaction and tanker loading

facility of 500,000 GJHHV/y.

The figures below summarize the technical characteristics, capital costs, operating,

and levelised costs for this infrastructure, considering the indicative delivery

distances of 50, 100, 150, 200 and 250 km.



Figure D.9

TALENT WITH ENERGY ASSUMPTIONS: RENEWABLE GAS INFRASTRUCTURE – ROAD TRANSPORT DELIVERY

TECHNICAL CHARACTERISTICS


Figure D.10

TALENT WITH ENERGY COST ASSUMPTIONS: RENEWABLE GAS INFRASTRUCTURE – ROAD TRANSPORT

DELIVERY CAPITAL COSTS




Figure D.11


DELIVERY OPERATING COSTS


Figure D.12


DELIVERY LEVELISED COSTS

9.407 9.417 9.428 9.439 9.449

0

2

4

6

8

10

50 100 150 200 250

Delivery distance, km

AU

D(2

012)

per

GJ(

HH

V)

L-SNG delivery: Levelized cost of gas delivery




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