Change and choice

The Future Grid Forum’s analysis of Australia’s 
potential electricity pathways to 2050



ACKNOWLEDGEMENTS

The Future Grid Forum was 
jointly funded by the electricity 
industry participants. The Future 
Grid Forum extends its special 
thanks to platinum sponsors GE 
and CSIRO and gold sponsors 
Ausgrid and Grid Australia.

DISCLAIMER

CSIRO advises that the information 
contained in this publication 
comprises general statements 
based on scientific research. The 
reader is advised and needs to be 
aware that such information may 
be incomplete or unable to be 
used in any specific situation. No 
reliance or actions must therefore 
be made on that information 
without seeking prior expert 
professional, scientific and 
technical advice. To the extent 
permitted by law, CSIRO (including 
its employees and consultants) 
excludes all liability to any 
person for any consequences, 
including but not limited to all 
losses, damages, costs, expenses 
and any other compensation, 
arising directly or indirectly from 
using this publication (in part or 
in whole) and any information 
or material contained in it. The 
views expressed in this report 
do not necessarily represent 
the views of any single or all 
participating organisations.

© 2013 CSIRO To the extent 
permitted by law, all rights 
are reserved and no part of 
this publication covered by 
copyright may be reproduced 
or copied in any form or by 
any means except with the 
written permission of CSIRO.

FUTURE GRID FORUM 
DELEGATES

Scott Agnew, Gwen Andrews, 
Brad Archer, Louise Avon-Smith, 
Paul Backscheider, Chris Baker, 
Alberto Balbo, Tom Barry, 
Stephanie Bashir, Stewart Bell, 
Darryl Biggar, David Bowker, John 
Bradley, Miguel Brandao, Jillian 
Broadbent, Paul Budde, Tom Butler, 
Mark Byrne, Simon Camroux, Lucy 
Carter, James Clements, Alan Coller, 
Peter Coppin, Catherine Cussen, 
Matthew Dalziel, Bob Darwin, 
Amandine Denis, Kieran Donoghue, 
Paul Dunn, Marcy Faith, Trevor 
Gleeson, Yochai Glick, Marty Grant, 
David Green, James Hetherington, 
David Hill, Jen Hocking, Lyndall 
Hoitink, Paul Howarth, Stephen 
Hunt, Amélie Hunter, Rob Jackson, 
Ramana James, Alida Jansen 
van Vuuren, Justine Jarvinen, 
Olivia Kember, Ishaan Khanna, 
Anne-Marie Kirkman, Rebecca 
Knights, Jack Kotlyar, Dave Lee, 
Chris Leverington, Madeleine 
Lyons, Gerald Marion, Peter 
Milbourne, Alan Millis, Frank 
Montiel, Rob Murray-Leach, Tim 
Nelson, Peter Newland, Bernard 
Norton, James O’Flaherty, Cameron 
O’Reilly, Gill Owen, Ray Pannam, 
Andrea Pape, Charles Pelz, Pam 
Pham, Glenn Platt, Charles Popple, 
Nadesan Pushparaj, Matt Rennie, 
Lee Richardson, Domenic Rotili, 
Anna Skarbek, Ramy Soussou, 
Brian Spalding, Michael Stoyanoff, 
Susan Streeter, Michelle Taylor, 
Kane Thornton, John Thwaites, 
Hao Tian, Keith Torpy, Tony 
Vassallo, Gregor Verbic, Milan 
Vrkic, Colin Wain, Glenn Walden, 
Chris Ward, Matthew Warren, 
Ben Waters, Neil Watt, Alistair 
Wells, Bryn Williams, Peter Wilson, 
David Wise, Alex Wonhas, Tony 
Wood, Ben Woodside, Hudson 
Worsley and Anna Zebrowski

PROJECT TEAM

Project sponsor: 
Alex Wonhas, CSIRO

Workshop chairperson: 
Mark Paterson, CSIRO

Project Leader: 
Paul Graham, CSIRO

Facilitation: Mary Maher, 
Mary Maher & Associates

Editor: Natalie Bartley, 
Say the Word Productions

CSIRO communications and 
design: Linley Davis, Sally 
Crossman and Siobhan Duffy

CSIRO modelling team: 
Paul Graham, Thomas 
Brinsmead, Simon Dunstall, 
John Ward, Luke Reedman, 
Tarek Elgindy, Geoff James, 
Alan Rai and Jenny Hayward

ROAM modelling team: 
Joel Gilmore, Nicholas 
Cutler and Ian Rose

Social dimensions team: 
Naomi Boughen, Zaida Contreras 
Castro and Peta Ashworth

ENQUIRIES SHOULD BE 
DIRECTED TO:

Paul Graham, Chief Economist, 
CSIRO Energy Flagship

PO Box 330, Newcastle 
NSW 2300 Australia

t +61 2 4960 6061
e paul.graham@csiro.au



Foreword

Australia’s electricity system is at a significant crossroads. Historically high retail 
electricity prices, widespread deployment of solar panels, greenhouse gas 
emissions abatement, and declining aggregate peak demand and consumption 
in most states are some of the major issues that have put it at this crossroads, 
and there are several potential future directions. Each direction has far-reaching 
implications for the future electricity supply chain and would alter the electricity 
model in this country. While many of these challenges also confront electricity 
supply in other parts of the world, Australia has its own set of unique strengths 
and vulnerabilities around which it will need to tailor effective solutions. 

Recognising the extraordinary circumstances of this time in the electricity 
sector’s history, in 2012 CSIRO convened the Future Grid Forum, unique in 
composition (bringing together more than 120 representatives of every segment 
of the electricity industry, as well as government and community) and in approach 
(undertaking extensive whole-of-system quantitative modelling and customer 
social dimensions research to support its deliberations and findings).

Many studies and reviews have evaluated the drivers of change now affecting 
the electricity system, but most have focused on specific parts of the system 
or been from the perspective of particular stakeholders. Australia’s electricity 
sector recognised that the system cannot be analysed and optimised by only 
examining its separate parts. A whole-of-system evaluation was essential.

Although there are many areas where the Future Grid Forum reached a high level 
of agreement, this report should not be interpreted as a consensus statement. 
Rather, it is a summary of the Forum’s journey and its key conclusions. Our intent 
is to help inform public discussion and policy settings around the challenges 
and opportunities Australia will face in managing electricity needs to 2050.




Future Grid Forum participants
December 2013



Participants

AGL logo
Alstom logo
Aurora Energy logo
Australian Council of Social Services (ACOSS)
Citipower Powercor Australia logo
Citipower Powercor Australia logo
Clean Energy Council logo
ClimateWorks Australia logo
Energex logo
Energy Efficiency Council logo
Energy Networks Association logo
Energy Retailer’s Association of Australia (ERAA) logo
Energy Supply Association of Australia (ESAA) logo
Ergon Energy logo
General Electric (GE) logo
Grattan Institute logo
GridAustralia logo
Hydro Tasmania logo
Landis+Gyr logo
Monash Sustainability Institute logo
Origin Energy logo
SA Power Networks logo
Siemens logo
Smart Grid Australia logo
South Australian Department for Manufacturing, Innovation, Trade, Resources and Energy logo
Stockland logo
Telstra logo
The Climate Institute logo
Total Environment Centre logo
University of Syndey logo
Western Power logo

Contents

Executive summary...................................................................................................................1

What might Australia’s electricity system look like in 2050?..........................................................................................2

What are the issues and options that might arise along the way?.................................................................................7

What can the electricity sector and its stakeholders do to most effectively plan and respond?..............................12

The conversation must continue.....................................................................................................................................12

Section 1: Future Grid Forum principles, processes and scenarios.............................................14

The four scenarios ...........................................................................................................................................................14

Section 2: The existing issues for electricity in Australia .........................................................17

‘Price shock’ in electricity supply....................................................................................................................................17

Decline in peak demand and consumption ...................................................................................................................20

Lack of connection between consumer prices and costs of services delivered..........................................................20

Greenhouse gas emissions, carbon policy and climate change vulnerability.............................................................22

Shifting attitudes to reliability and its cost ....................................................................................................................23

Section 3: Future Grid Forum scenario origins and assumptions...............................................25

General uncertainties.......................................................................................................................................................25

Megashifts.........................................................................................................................................................................30

Consumer choices.............................................................................................................................................................31

Section 4: The emerging issues for electricity in Australia .......................................................37

Implications of shifting attitudes to reliability and the potential for customer disconnection.................................37

Implications for costs and electricity bills......................................................................................................................39

Addressing the risk of declining network utilisation ....................................................................................................48

Implications of the lack of connection between consumer prices and service costs ................................................51

Implications of greenhouse gas abatement and carbon policy uncertainty...............................................................55

Implications of the electricity system’s vulnerability to climate change .....................................................................55

Section 5: A potential path forward.........................................................................................57

The Forum’s proposed framework for evaluating outcomes........................................................................................57

Impacts by segment and scenario...................................................................................................................................59

Proposed options for addressing the issues identified in the scenario modelling.....................................................61

References.............................................................................................................................68

Glossary ................................................................................................................................70



Figures

Figure 1: Historical average national electricity retail prices (2013 dollars)......................................................................17

Figure 2: Changes in real regulated residential retail electricity price components 
(New South Wales, 2012–13 dollars)......................................................................................................................................18

Figure 3: Components of state regulated retail electricity prices in 2012–13....................................................................18

Figure 4: Historical residential air-conditioner adoption.....................................................................................................19

Figure 5: Index (2005–06=100) of historical consumption (TWh) in NEM states...............................................................21

Figure 6: Index (2005–06=100) of historical peak demand (GW) in NEM states................................................................21

Figure 7: Historical electricity sector greenhouse gas emissions........................................................................................22

Figure 8: Future Grid Forum scenario development framework.........................................................................................25

Figure 9: East coast coal and natural gas price projections.................................................................................................26

Figure 10: Treasury (2011) and modified Future Grid Forum carbon price trajectories....................................................27

Figure 11: Alternative 2050 capital cost assumptions for large-scale centralised electricity 
generation technologies.........................................................................................................................................................28

Figure 12: Alternative 2050 capital cost assumptions for on-site electricity generation technologies...........................29

Figure 13: Projected percentage reductions in storage costs and the Future Grid Forum assumed 
cost reduction trajectory.........................................................................................................................................................31

Figure 14: Projected electricity consumption supplied by the grid and on-site generation (NEM total).........................33

Figure 15: Projected electricity consumption supplied by the grid (NEM total)................................................................34

Figure 16: Projected share of on-site generation (all states)................................................................................................34

Figure 17: Projected aggregate peak demand to be met by centrally-supplied electricity (NEM total)...........................35

Figure 18: Projected distribution network aggregate load factor under the Future Grid Forum scenarios....................39

Figure 19: Projected distribution system unit costs (real 2013 Australian dollars)............................................................40

Figure 20: Projected average wholesale electricity unit costs by scenario and a zero, high and uncertain 
carbon price sensitivity on Scenario 1...................................................................................................................................41

Figure 21: Projected average wholesale electricity unit costs and per cent below 2000 greenhouse gas emission 
levels in 2050 by scenario and a zero and high carbon price sensitivity on Scenario 1 compared to 2013....................43

Figure 22: Projected unit cost of retail electricity supply from the centralised grid by scenario.....................................44

Figure 23: Projected cumulative system cost by scenario to 2050......................................................................................44

Figure 24: Projected net annual electricity cost (retail bill minus PV export payments plus amortised 
on-site costs where relevant) under alternative scenarios and household types..............................................................45

Figure 25: Residential electricity share of income in 2030 and 2050 by scenario..............................................................47

Figure 26: Megawatt hours of electricity required per million dollars of output by industry category..........................48

Figure 27: Index (2013=100) of projected changes in commercial and industrial electricity bills....................................49

Figure 28: Projected electricity consumption from road electrification by scenario........................................................50

Figure 29: Evolution of business models: what’s possible? .................................................................................................53



Tables

Table 1: Four general tariff options for consideration.........................................................................................................51

Table 2: Future Grid Forum’s proposed key performance indicators..................................................................................57

Table 3: Summary of current and future supply chain segment impacts by scenario........................................................60

Table 4: Summary of proposed options for addressing the major issues identified in the 
Future Grid Forum’s modelling..............................................................................................................................................61



Executive summary

The electricity system is central to Australia’s modern lifestyle 
and economy. It has served the nation very well and will 
continue to do so for some time, but it is now facing complex 
and unprecedented challenges. These challenges have the 
power to affect all links in the electricity supply chain and to 
encourage new market structures, actors, and business models to 
emerge. The future is likely to look vastly different from today. 

The Future Grid Forum explored these challenges and extensively 
modelled four scenarios to ask these important questions:

..What might Australia’s electricity system look like in 2050? 
..What are the issues and options that might arise along the way?
..What can the electricity sector and its stakeholders 
do to most effectively plan and respond?


The Future Grid Forum offers its findings and invites a national 
conversation to decide the right answers for the sector, its 
stakeholders and, most importantly, all Australians.



What might Australia’s electricity system look like in 2050?

Many drivers of future change already exist. Some events explored in the Forum’s scenarios are a 
reaction to or an extrapolation of recent issues and developments in the electricity sector: 

Electricity bills have 
risen

Since 2007 the average household electricity price has increased by two-thirds, from 
around 15 cents per kilowatt hour to over 25 cents per kilowatt hour in 2012. Reduced 
consumption and rising incomes for some consumers moderated the impact of this 
price increase on electricity bills; nevertheless, the scale of these price increases has 
represented a ‘price shock’ to Australian consumers. The causes are complex, various and 
differ by state, but investment in the electricity distribution system for asset replacement 
and refurbishment as well as compliance with reliability licence conditions and capacity 
to meet growing demand played the largest role. The carbon price and various state 
feed-in tariffs have also contributed.

Peak demand and 
consumption have 
reversed trend in most 
states since 2008–09

Coinciding with the ‘price shock’ in the market, peak demand and consumption both 
reversed trend and declined in most Australian states. Energy conservation, on-site 
generation (solar photovoltaic), weather conditions (La Nina), and industry evolution 
(growth of services businesses over manufacturing) drove this decline and the future 
trend in consumption and peak demand is now highly uncertain.

There is an oversupply 
of generation capacity

Decreasing consumption, past investments in coal and gas generation assets and, more 
recently, deployment of wind power (as the main renewable generation platform under 
the Renewable Energy Target) have led to an oversupply of generation capacity in the 
wholesale market. This economic reality has led to some generation capacity being 
mothballed or retired early and this comes at a cost to the owners of those assets. 

Residential electricity 
prices are not well 
aligned with the costs 
of services

Given the prevalence of volume-based pricing, most residential consumers do not receive 
cost-reflective pricing signals from the electricity system. Residential consumers are 
engaging more with their electricity supply (as the adoption of on-site generation and 
energy efficiency indicates), but they remain unaware of the impact of peak power use 
on electricity system costs and have limited incentive to act to address it. 

Australia’s electricity 
supply has started 
to decarbonise, but 
a substantial task 
remains

Greenhouse gas emissions from electricity generation in Australia peaked in 2008 
at 208 million tonnes of carbon dioxide equivalent, but had fallen by 8 per cent to 
191 million tonnes of carbon dioxide equivalent by December 2012. Yet the electricity 
sector remains the largest single source of Australian emissions, and substantial further 
decarbonisation is required over coming decades if Australia is to contribute its fair share 
to the global greenhouse gas abatement task. 

There is uncertainty 
around carbon policy 
in Australian politics

While Australia has a bipartisan greenhouse gas abatement target of a 5–15 per cent 
reduction on 2000 levels by 2020 (or a 25 per cent reduction if there is stronger 
international action), there is ongoing disagreement on the appropriate policy 
mechanisms to deliver these targets and on longer-term reduction targets. Given the 
long life of electricity system assets and the scale of greenhouse gas emissions from the 
electricity sector, this uncertainty presents a significant investment risk and has flow-on 
impacts to consumers.

Attitudes towards 
electricity system 
reliability and its cost 
are shifting

While reliability has become more important over time as Australia’s lifestyle and 
industry have come to depend more on electricity, the contribution to the recent 
electricity price rises of infrastructure spending to meet reliability standards led many 
to question whether reliability standards are now set too high or too prescriptively in 
some jurisdictions.







Against this backdrop, the Forum believes Australia’s electricity landscape will change 
significantly in the decades to 2050, and the greatest changes are likely to come from:

..‘megashifts’ brought on by the advent of low-cost electricity storage, sustained low demand 
for centrally-supplied electricity, and the need for significant greenhouse gas abatement 
..consumer choice as an outcome of potential new business models, a greater degree 
of cost-reflectivity in pricing, and a higher overall level of consumer engagement. 


Fuel prices, any carbon and energy policies and their specific targets and 
mechanisms, changes in the costs of other technologies, and any adaptation to a 
changing climate will also create significant uncertainties for the system. 

If the electricity sector is to effectively plan and respond to these changes, it is 
important for it to fully understand how all of this might play out. But in exploring 
and presenting possibilities through its scenarios, the Forum notes: 

..The actual future might include elements of each of the scenarios. 
..For each scenario, every segment of the electricity supply chain would be affected differently. 
..There is no future scenario that is universally advantageous to all stakeholders. 
..The Forum does not endorse any particular scenario as being the most likely or the most desirable.




THE FUTURE GRID FORUM’S FUTURE SCENARIOS AND THEIR POTENTIAL IMPACTS 
ON THE SUPPLY CHAIN

Scenario 1: ‘Set and forget’

Sustained high retail prices, heightened awareness about the issue of peak demand, and new business 
opportunities lead residential, commercial and industrial customers to adopt peak demand management.

But, recognising the busy lives of many customers, the demand management systems are designed to be on a 
‘set and forget’ basis after customers have decided which level of demand management suits them.

Measures include building large-appliance control (air-conditioning, pumps), on-site storage, specialised 
industrial demand reduction markets, and electric vehicle charge management, as well as advanced metering 
and communication to enable these services.

Set and forget infographic: Central control to commercial, industrial and residential customers
CENTRALCONTROLCustomer-centric modelwhere customers consume, trade, 
generate and store electricity.
CENTRALCONTROL

Scenario 2: ‘Rise of the prosumer’

Continued falling costs of solar photovoltaic panels and other on-site generation technologies, sustained high 
retail prices, and increasingly innovative financing and product packaging from energy services companies leads 
to the widespread adoption of on-site generation.

Residential consumers in particular are empowered by their choice to become more actively engaged in their 
electricity supply and call themselves ‘prosumers’. Electric vehicle adoption is also popular.

The use of on-site generation is also strong in commercial and industrial customer sectors, but with a stronger 
preference for cogeneration or trigeneration technologies. By 2050, on-site generation supplies almost half 
of all consumption.

Rise of the prosumer infographic: Customer-centric model where customers consume, trade, generate and store electricity.
CENTRALCONTROLCustomer-centric modelwhere customers consume, trade, 
generate and store electricity.




Scenario 3: ‘Leaving the grid’

The continued dominance of volume-based pricing among residential and small commercial consumers encourages 
energy efficiency without accompanying reductions in peak demand growth. The subsequent declining network 
utilisation feeds increases in retail prices.

New energy service companies sensing a market opportunity invite consumers to leave the grid, offering an initially 
higher-cost solution but one that appeals to a sense of independence from the grid. Consumers have already become 
comfortable using small amounts of storage on-site and in their vehicles and a trickle of consumers takes up the offer. 

By the late 2030s, with reduced storage costs, disconnection becomes a mainstream option and the rate of 
disconnection accelerates. Customers remaining on the system are those with poor access to capital and industrial 
customers whose loads can’t be easily accommodated by on-site generation.

Leaving the grid infographic: Sun to solar panels on house to battery to car
CENTRALCONTROLCustomer-centric modelwhere customers consume, trade, 
generate and store electricity.
CENTRALCONTROL

Scenario 4: ‘Renewables thrive’

Confidence in the improving costs of renewable technologies, achieved by combined efforts from government and 
industry around the world, results in the introduction of a linearly phased 100 per cent renewable target by 2050 
for centralised electricity generation.

To shift demand and meet renewable supply gaps, storage technology is enabled to achieve the target at utility, 
network and consumer sites.

Some customers maintain on-site back-up power (for example, diesel) for remote and uninterruptible power 
applications, offsetting their emissions by purchasing credits from other sectors, such as carbon forestry.

Overall, the renewable share, taken as a share of both centralised and on-site generation, is 86 per cent by 2050.

Renewables thrive infographic: Central control to renewable energy - wind, solar, battery
CENTRALCONTROLCustomer-centric modelwhere customers consume, trade, 
generate and store electricity.
CENTRALCONTROL



SUMMARY OF SUPPLY CHAIN SEGMENT IMPACTS BY SCENARIO

STAKEHOLDER

Scenario 1:
‘Set and 
forget'

Scenario 2: 
‘Rise of the 
prosumer’

Scenario 3: 
‘Leaving the 
grid’

Scenario 4: 
‘Renewables 
on tap’

Residential consumer

Modest change


Substantial change


Vastly different


Significant change


Commercial or industrial customer

Modest change


Substantial change


Vastly different


Significant change


Retailer

Modest change


Substantial change


Vastly different


Significant change


Distribution

Significant change


Substantial change


Vastly different


Substantial change


Transmission

Significant change


Substantial change


Substantial change


Substantial change


Generation and transmission system 
operators

Significant change


Substantial change


Substantial change


Vastly different


Energy service companies

Modest change


Vastly different


Vastly different


Substantial change


Metering services

Significant change


Vastly different


Substantial change


Vastly different


Centralised generator – coal

Substantial change


Vastly different


Vastly different


Vastly different


Centralised generator – gas

Vastly different


Vastly different


Vastly different


Modest change


Centralised generator – renewable

Modest change


Significant change


Significant change


Vastly different


On-site generators

Modest change


Substantial change


Vastly different


Significant change


Storage technology providers

Significant change


Substantial change


Vastly different


Vastly different


Electric vehicle providers

Significant change


Substantial change


Substantial change


Vastly different


Information and communication 
technology

Modest change


Substantial change


Significant change


Significant change






KEY: 

Modest change 
= Modest change, manageable within existing structures and business models

Significant change 
= Significant change; some new activities emerge but within existing structures

Substantial change 
= Substantial change where new business models and market structures are required

Vastly different 
= Vastly different from today; most existing activities and business models completely change



What are the issues and options that might arise along the way?

From the Forum’s modelling, it became clear that Australia’s electricity system will face significant issues 
during the decades to 2050 and each of these issues will bring its own challenges, risks and barriers. 
While the electricity sector cannot fully predict or control any changes these issues would bring—and the 
scale of the electricity system and its investments mean these changes could take decades to address—
it could position the electricity market so that it is better able to respond and transition effectively. 

The major issues identified through the Forum’s modelling and some options for addressing 
them are presented here. These options are intended only to set out broad principles for 
consideration. Ongoing conversations among all stakeholders will be necessary to achieve 
detailed understanding and consensus within the Australian community. The options are not 
mutually exclusive; given it is not possible to predict which scenario events will occur and 
in what combination, the options could be combined or implemented in parallel. 



THE FUTURE GRID FORUM’S SUMMARY OF MAJOR ISSUES AND OPTIONS FOR ADDRESSING THEM

ISSUE

CHALLENGES





Investment in new generation

Wholesale electricity generation prices are projected to remain below that 
which would be required to build new plant and recover a reasonable return on 
investment until the early 2020s.

Wholesale prices need to increase from around $40/MWh (4 c/kWh) in 2013 
(excluding the carbon price) to around $70/MWh (7 c/kWh)1 (excluding any 
future carbon price or equivalent mechanism) to be viable for new plant.











Managing peak demand

Limiting growth in peak demand is projected to save 2 c/kWh each year on the 
costs of electricity distribution between 2020 and 2050.

Peak demand has declined recently in some states and its future rate of growth 
is uncertain. If peak demand growth recovers in the future, it may contribute to 
declining network utilisation.















Increased on-site generation

On-site generation is projected to reach 18–45 per cent of total generation by 
2050. This leads to a decline in network utilisation that is not driven by a lack of 
effort in managing peak demand, but rather a shift in the source of electricity 
generation from the grid to the user.











Disconnection from the grid

Disconnecting from the grid as a residential consumer is projected to be 
economically viable from around 2030 to 2040 when independent power 
systems are expected to be able to match retail prices of 35–40 c/kWh as 
battery costs fall.

Current costs of disconnecting are estimated at 
92–118 c/kWh (around four times 2013 retail prices).















Rising residential electricity bills, 
but stable as a share of income

As a result of increasing whole-of-system costs, by 2030 residential electricity 
bills are projected to be 2–9 per cent above 2013 levels.

Some vulnerable residential consumers, for whom electricity is a large 
component of their overall expenses, could experience some hardship.

However, the combined effect of adoption of energy efficiency, on-site 
generation, and general wages growth means, for the average wage earner, 
the electricity share of income is projected to be slightly lower than 2013 
in 2030 and return to similar levels by 2050 (between 9 per cent below, and 
14 per cent above, 2013 across the scenario range).





















1 All prices and their percentage changes are in real terms.



ISSUE

CHALLENGES





Large commercial and industrial 
customers’ electricity costs

As a result of their relatively strong exposure to costs of generation, which are 
projected to increase to achieve greenhouse gas emission reduction (see next 
point), large commercial and industrial customers are expected to experience 
an increase in electricity bills, primarily after 2020.

By 2030, large commercial customers who adopt energy-efficiency measures are 
projected to limit the increase in their electricity bills to 1.1–2.2 per cent a year.

Industrial customers (assuming no change in electricity efficiency) could face 
an increase in electricity bills of 1.6–3.0 per cent a year to 2030 across the 
scenario range.















Electricity sector emissions

Across the scenarios, the electricity sector is projected to achieve greenhouse 
gas emission reduction of 55–89 per cent below 2000 levels by 2050. This is 
reasonably consistent with the currently legislated national greenhouse gas 
emission reduction target of 80 per cent below 2000 levels by 2050.

To achieve this emission reduction, wholesale electricity unit costs 
increase from approximately $60/MWh in 2013 to between $113/MWh 
(11.3 c/kWh) and $176/MWh (17.6 c/kWh) in 2050. Against this cost, the 
benefits of avoided climate change were not estimated (however, see 
‘Climate change adaptation’ below).







Carbon policy uncertainty

The wholesale electricity price is projected to be 17 per cent ($24/MWh or 
2.4 c/kWh) higher by 2050 if long-term carbon policy uncertainty is 
not resolved.









Climate change adaptation

Where the risk of climate change results in networks building to a higher 
probability of extreme peak demand events, then unit electricity costs are 
projected to be 2.8 c/kWh higher on average each year between 2025 and 
2050. Impacts of extreme weather generally and costs of other electricity 
sector climate change adaptations were not estimated, but are also 
very relevant.











Increasing natural gas prices

Wholesale electricity prices are projected to be $11/MWh (1.1 c/kWh) higher 
and greenhouse gas emissions 34 per cent higher by 2050 relative to Scenario 1 
if there is a higher rate of growth in gas prices.









The role of nuclear power

Wholesale electricity prices are projected to be $34/MWh (4 c/kWh) lower and 
greenhouse gas emissions 72 per cent lower by 2050 relative to Scenario 1 if 
nuclear power is included in the electricity generation mix.

















What can the electricity sector 
and its stakeholders do to most 
effectively plan and respond?

Many of the options the Forum offers in this 
summary table are not new, but rather support 
existing processes or market arrangements. 
However, the Forum believes that mechanisms 
to accelerate these processes should be 
investigated given that electricity markets 
have shown the tendency to undergo major 
and rapid shifts that are able to outpace the 
reform processes’ ability to implement change. 
In addition, the Forum suggests expanding 
the scope of the Australian Energy Technology 
Assessment to include on-site generation and 
storage technologies because of their potential 
to shape the future of the electricity system.

Of the options presented in the summary table, 
there are four that are not already established but 
could be considered as potential approaches to 
addressing the issues identified in the scenarios:

1. Implement a sustained long-term program 
to increase consumer awareness of the 
benefits and mechanisms of cost-reflective 
pricing and demand management. 
2. Develop bipartisan agreement on the long-term 
(2050) greenhouse gas emission target and 
implementation mechanism for Australia.
3. Review Australia’s electricity consumer 
social safety net.
4. Establish processes to identify the 
changes, if any, that might be required 
to market frameworks in light of the 
megashifts examined in this report.


EVALUATING OUTCOMES

The Forum developed a framework of five key 
performance indicators for evaluating electricity 
sector outcomes for Australia, based on the 
recognition that how much any of these issues 
and their outcomes matters is directly linked 
to how much value people place on them. 
This framework helped to focus the Forum’s 
deliberations and could be a useful tool for 
other electricity sector analysis in future. 

SUMMARY OF THE FUTURE GRID FORUM’S 
PROPOSED KEY PERFORMANCE INDICATORS

KEY 
PERFORMANCE 
INDICATOR

DEFINITION 

Whole-of-system 
cost

The total cost of electricity 
consumed by end-users, inclusive 
of generation, distribution, 
transmission, retail and any on-site 
costs that the end-user incurs, in 
order to obtain the desired services 
that electricity enables

Reliability

The extent to which the supply and 
quality of electricity is maintained at 
a given level

Greenhouse gas 
emissions

Emissions from the electricity sector 
contributing to climate change

Service and price 
customisation

The degree to which customers can 
access an electricity contract that 
matches the electricity supply and 
other services they need and want, 
and the degree to which the price 
they pay for this contract matches 
the actual cost the services impose 
on the system 

Resilience

The ability of the electricity system to 
recover from and adapt to shocks such 
as those from technological, market, 
social, and environmental changes 





The Forum recognises that while each of these key 
performance indicators is desirable, they do not 
perfectly align and this makes setting goals and 
objectives for the electricity system challenging. 
Trade-offs among potential outcomes will be necessary. 
The Forum did not seek to determine the best trade 
off of the key performance indicators, but rather to 
highlight these trade-offs and potential alternative 
outcomes under different future scenarios. 

The conversation must continue

The Future Grid Forum believes the nation has 
to continue this crucial conversation about the 
future of electricity in Australia. It presents its 
findings as a starting point so that the electricity 
industry, its stakeholders, and the community can 
fully understand, manage, and benefit from the 
many changes and choices now emerging. 

The companion report, Modelling the Future Grid Forum 
scenarios, presents the quantitative modelling of the 
Future Grid Forum’s scenarios and sensitivity cases.



Section 1: Future Grid Forum 
principles, processes and scenarios

The Future Grid Forum examined the future of 
electricity in Australia across all links in the electricity 
supply chain, and discussed and (where possible) 
agreed on the existing and emerging issues facing 
the system. From there, the Forum formulated some 
options for transitioning the electricity system through 
the period of great change to 2050. The Forum hopes 
that sharing its findings will inform and inspire an 
ongoing conversation about Australia’s energy future 
and support the electricity system to most effectively 
manage the risks and opportunities to 2050.

Over 15 months, the Future Grid Forum: 

1. analysed the existing and future issues 
facing Australia’s electricity system 
2. envisioned four ‘electricity future’ scenarios 
for Australia and used these as a framework 
for extensive quantitative modelling, 
analysis and social dimensions research 
3. developed an evaluation framework for 
defining a high-performing electricity 
system for Australia and for evaluating the 
outcomes and trade-offs that the changes 
occurring in the sector might bring about
4. identified a set of options for positioning the 
electricity system to most effectively plan 
and respond to its challenges to 2050. 


The four scenarios 

Each of the Future Grid Forum’s four scenarios 
is a potential pathway for electricity in Australia. 
The scenarios are presented here for context and 
are referred to throughout the report. The Forum 
does not endorse any particular scenario as being 
the most likely or the most desirable. For each 
scenario, every stakeholder in the electricity 
system would be affected differently. There is no 
scenario that is universally advantageous to all 
stakeholders. The scenarios explore some topics 
and exclude others and, in reality, the actual 
future might include elements of each scenario.

To better understand the effects of the 
assumptions within each scenario, the Forum 
explored some sensitivity cases. The companion 
report, Modelling the Future Grid Forum scenarios, 
presents details of the quantitative modelling 
of the scenarios and the sensitivity cases.

Scenario 1: ‘Set and forget’

Following continued retail price rises to 2015 
and clear messages to customers that peak 
demand growth is a significant cause, residential, 
commercial and industrial customers become 
open to taking up demand management.

Tariff deregulation makes available a wider 
variety of management options. The level 
of customer engagement is light, however, 
and customers prefer to rely on their utility 
company for the solutions for contracting, 
integrating, and operating demand response. 

Customers lead busy lives and want to ‘set and 
forget’ their demand management once they’ve 
worked out which level of demand control suits 
them. For example, most pool owners switch 
to off-peak filtration and time-of-use pricing.

In time, nearly all household and commercial 
air-conditioning systems are central-control 
enabled. Smart meters are ubiquitous, providing 
the infrastructure for pricing arrangements, 
inclusion of other large appliances in demand 
management schemes, and efficient operation 
of on-site storage to shift demand when it 
is not practical to ramp down appliances. 

Specialised markets for industrial demand 
reduction are streamlined. Customers take 
up on-site generation and electric vehicles, 
but, overall, centralised power and liquid-
fuelled transport remain dominant because 
they are still cost-competitive and meet 
customer needs in most applications.



Scenario 2: ‘Rise of the prosumer’ 

Over several decades, lowering costs of solar 
photovoltaic panels and inverters has meant that 
eventually nearly every residential consumer with a 
usable roof space takes up solar power. Not owning a 
home does not prevent uptake because panels become 
no more difficult to move between rental properties 
than a refrigerator, and apartments allocate available 
roof space or use solar photovoltaic cladding.

The domestic consumer interest in on-site 
generation spreads to other technologies, such 
as gas-powered systems, and commercial and 
industrial customers take up cogeneration and 
trigeneration systems, both supported by gas 
price increases that were less than anticipated.

Distribution service providers, retailers, and energy 
service companies embrace prosumers’ needs and 
compete to provide them with financing arrangements 
where needed and the best opportunities for 
trading power or using it on site through storage 
systems. The network provides the platform for 
transactions, while a variety of companies compete 
to carry out the integration and facilitation roles.

Consumers choose the level of control they require 
from a wide variety of plans. A popular plan 
involves using batteries from electric vehicles as 
storage at the end of their vehicle life. Electric 
vehicles come to dominate passenger and light 
commercial vehicle transport, substantially 
reducing the demand for oil in Australia.

Scenario 3: ‘Leaving the grid’

The continued dominance of residential 
volume-based pricing encourages energy 
efficiency without accompanying peak 
demand reduction. Poor export prices and 
other price signals encourage residential 
and commercial customers who have on-
site generation to seriously explore using 
storage more substantially to maximise 
the value of their on-site generation. 
Large-scale uptake of electrification for light 
vehicles reinforces customers’ increasing 
comfort with operating storage systems.

New energy service companies sensing a 
market opportunity make available building 
control systems and interfaces that take care 
of most of the details for the customer.

As battery costs decline, an increasing number 
of customers begin to wonder whether there 
is sufficient benefit in staying connected 
(much like they did with landlines during 
the rapid uptake of mobile phones). A trickle 
of disconnections becomes an avalanche 
because, in a self-reinforcing cycle, all 
other things being equal, retail prices must 
continue to rise as the system becomes 
more and more underutilised with each 
disconnection. Customers remaining on the 
system are those with poor access to capital 
and industrial customers whose loads can’t be 
easily accommodated by on-site generation.

Scenario 4: ‘Renewables thrive’

By 2025, renewable electricity generating technologies are found to cost less than expected, largely 
as a result of deliberate programs and targets introduced in countries across the world to deploy them 
and bring down their costs. While a moderate carbon pricing scheme is maintained for the remainder 
of the economy, the success of these renewable target policies results in the introduction of a linearly 
phased 100 per cent renewable target by 2050 for the centralised electricity generation sector. 

Besides emission reduction, the renewable target is also seen as an opportunity for Australia to build 
new technology supply industries and to develop regions expected to be the focus of renewable 
deployments. Accompanying this policy are deliberate incentives to adopt storage in place of natural gas 
as the primary back-up system for managing peak demand and renewable energy supply variability.

Storage is deployed both at utility-scale and network locations as well as on-site with customers, shifting 
demand and storage charging loads to the middle of the day to take advantage of high large-scale solar 
and decentralised rooftop solar output. The network is tasked with integrating these processes. Some 
customers maintain on-site back-up power (for example, diesel) for remote and uninterruptible power 
applications, offsetting these emissions by purchasing credits from other sectors, such as carbon forestry. 
Residential, commercial and industrial customers all participate in peak demand management. 

Overall, the renewable share, taken as a share of both centralised and on-site generation, is 86 per cent by 2050.



Section 2: The existing issues for 
electricity in Australia 

Complex and unprecedented issues are confronting 
Australia’s electricity system. They span climate 
change, changing energy consumption patterns, fuel 
source diversity, rising costs, social inequity, and 
accommodating new technologies and the digital 
age. Some of these issues have been at play over the 
past five years; some are more recent and continue 
to evolve. Taken together, a clearer picture of the 
current landscape for electricity in Australia emerges.

‘Price shock’ in electricity supply

In the second half of last century, real Australian 
electricity prices had been declining or fairly stable, 
with the exception of the early 1980s (Figure 1); 
however, since 2007 the average regulated household 
electricity price has increased by two-thirds, from 
around 15 cents per kilowatt hour to over 25 cents 
per kilowatt hour in 2012 (all currency in this report 
is expressed in real 2013 Australia dollars). This is 
around the levels experienced in the 1950s (adjusted 
to today’s dollars), but household electricity use has 
increased considerably since that time. The causes 
of this price increase are complex, various and 
differ by state, but investment in the electricity 
distribution system played the largest role. 

As an example, a breakdown of changes in the 
components of retail costs for New South Wales’ 
regulated residential price is presented in Figure 2. 
Note that the cost components in each state vary 
somewhat from the New South Wales trend as a result 
of variations in each state’s circumstances (Figure 3). 
Also, market prices can be significantly below the 
regulated prices shown in both Figures 2 and 3.

In New South Wales, total network costs (comprising 
77 per cent distribution and 23 per cent transmission 
costs in 2012–13) increased by 7.1 cents per kilowatt 
hour between 2007–08 and 2012–13, accounting for 
60 per cent of the total increase in retail prices. 

The carbon price has added 2.1 cents per kilowatt 
hour, but only since its introduction in July 
2012; other factors have increased incrementally 
throughout the period. Tax changes for low-income 
groups2 and partial exemptions for export-exposed 
industries have offset the effect of the carbon price 
to some extent. The Commonwealth Government’s 
Renewable Energy Target (RET) and state 
government schemes, such as solar feed-in tariffs, 
have also contributed to higher electricity prices, 
adding around 1 cent per kilowatt hour (Figure 3) 
(although the RET has had the counteracting effect 
of lowering wholesale prices, as discussed below).

For a description of this image please contact paul.graham@csiro.au
Figure 1: Historical average 
national electricity retail 
prices (2013 dollars)

Source: ESAA (various); 
ABS (2013a)

2 Called the Government Household Assistance Package.



Figure 2: Changes in real 
regulated residential retail 
electricity price components 
(New South Wales, 2012–13 
dollars)

Source: IPART (2013); 
AEMC (2013a)

For a description of this image please contact paul.graham@csiro.au
Figure 3: Components 
of state regulated retail 
electricity prices in 2012–133

Source: AEMC (2013a)

3 It is important to note that these prices should be discounted. Market offers were lower than these regulated prices and remain so; however, no 
other source provides a consistent breakdown for all states. The roll-out of advanced metering in Victoria is included in the retail component and is 
unique to that state. Prices are exclusive of good and services tax (GST).


For a description of this image please contact paul.graham@csiro.au

One factor that actually reduced pressure on 
retail prices during the past five years, but not 
enough to offset the increases in other factors, 
was lower generation costs. A recent unexpected 
decline in electricity consumption together with 
greater renewable generation has led to excess 
supply in the generation market, depressing 
wholesale prices. Several generation plants 
have been mothballed or retired as a result.

The reality of the depressed wholesale market is 
in conflict with the information in Figure 2, which 
suggests that wholesale costs have risen; however, 
the wholesale costs in Figure 2 refer to the costs of 
building new plant4 not actual wholesale market 
prices, which have been significantly below plant 
replacement costs. Only investment in renewable 
generation capacity required by the RET is proceeding 
under these market conditions. When and if additional 
generation capacity investment is needed above 
that required to meet the RET, wholesale prices will 
need to increase. Indeed, with the risk of a low/zero 
carbon price in the period to 2020, there are concerns 
that the wholesale price may not be sufficient to 
even allow the RET to be met, despite the extra 
payments the scheme affords renewable plant.

Several factors drove the increase in the distribution 
component of retail electricity prices in Australia, but 
the pressures were not the same in each jurisdiction. 
Some states raised their reliability standards in 
an effort to meet assumed customer demand for 
lower incidence and duration of interruptions, 
and this required system expansion, while in other 
jurisdictions, aged network infrastructure, which was 
rapidly built in the household modernisation era of 
the 1950s and 1960s, had to be replaced. The global 
financial crisis increased the financing costs for 
these activities. 
There was also additional network expenditure to 
ensure there was sufficient capacity to meet peak 
demand.5 Expectations of rising peak demand were 
partly driven by increasing air-conditioner ownership 
among Australians, which doubled from around 35 
per cent in 2000 to over 70 per cent in 2012 (Figure 4). 
Network capacity has been sized to provide power on 
days when air-conditioner usage is high because of 
weather extremes—and these same extremes lower 
the effective capacity of the network. Peak demand 
increased significantly in most states up to 2008–09, 
but expectations of further increases were not 
realised in the period 2008–09 to 2012–13 (Figure 6).

For a description of this image please contact paul.graham@csiro.au
Figure 4: Historical 
residential air-conditioner 
adoption

Source: DEWHA 
(2008); ABS (2011)

4 This was the preferred calculation method for wholesale costs in New South Wales’ regulated retail prices.

5 ‘Peak demand’ is the highest instantaneous level of demand experienced in a given period, expressed in watts, whereas ‘consumption’ refers to the 
total volume of electricity consumed over a given period expressed in watt-hours.



Decline in peak demand 
and consumption 

Usually climbing inexorably with economic growth, 
in most Australian states aggregate peak demand 
and consumption have both reversed trend and 
declined since around 2008–096 (Figures 5 and 6). 
There are no state-level baseline studies on energy 
customer behaviour to accurately determine the 
relative strengths of the various causes of the 
aggregate changes, but these factors played a role: 

..Some consumers responded to the price shock 
by adopting energy efficiency and energy 
conservation measures and changed usage patterns 
in an effort to reduce their electricity bills. 
..State and federal government incentives and falling 
costs of on-site generation systems supported 
customers’ adoption of solar hot water and rooftop 
solar photovoltaic power systems, reducing their 
need for electricity from the centralised network.
..Manufacturing and minerals processing activity 
(including electricity-intensive aluminium refining 
and steel production) declined as a result of a 
range of factors, including lower commodity prices 
and the historically high Australian dollar through 
2011 and 2012 (although it has eased in 2013).
..A prevailing La Nina weather pattern from 2010 to 
2011 described as the ‘strongest in living memory’7 
resulted in cooler summers and consequently less 
use of residential and commercial air-conditioning.


Lack of connection between 
consumer prices and costs 
of services delivered

While faster growth in peak demand relative to 
consumption was a partial cause of electricity price 
increases, it could be said that the much deeper 
cause is the lack of connection between consumer 
prices and the costs of services delivered to small 
consumers who largely remain on volume-based 
tariffs (larger customers are charged on the 
basis of both volume and peak demand). Lack of 
cost-reflective pricing means there is no signal 

to small consumers that greater use of high 
instantaneous power-demanding appliances will 
increase the per unit cost of consumption for the 
system as a whole. The dominance of volume-
based electricity contracts for small consumers 
has effectively meant that consumers with high 
peak demand are subsidised by those with low 
peak demand but similar consumption levels.

There are some longstanding partial exceptions 
in each state where volume-based price signals 
also include some incentive to small consumers to 
shift peak demand. For example, many states have 
traditionally had strong off-peak tariff schemes 
for hot water. More recently, Queensland was 
successful in attracting 59 per cent of Energex 
consumers to off-peak hot water, pool filtration 
and air-conditioning. Victoria increased its 
smart meter penetration to almost 90 per cent 
in 2013 and has introduced flexible tariffs that 
reflect the electricity price at time of use. Some 
examples of alternative tariff models and their 
advantages and disadvantages for consumers 
are explored later in this report (Table 1).

Another issue relating to cost of services is a fair 
payment for consumers’ exports of household 
roof-top solar photovoltaic electricity. Feed-in tariffs 
implemented in 2008 and 2009 across Australia 
initially set the price to encourage investment 
rather than to reflect their value in the market. Since 
governments pulled back feed-in tariffs in 2010 and 
2011 for new contracts signed, feed-in tariffs have 
decreased considerably (down from as high as 60 cents 
per kilowatt hour in New South Wales to 5–10 cents 
per kilowatt hour in different states), and this has 
opened a debate about what payment is reflective of 
their value. For the consumer receiving the exported 
solar panel output, the electricity is at least as valuable 
as the retail electricity price they would otherwise 
pay; however, the feed-in tariff should be less than the 
retail price because consumers exporting solar panel 
electricity use the distribution system for exporting 
and therefore they should provide some payment for 
this use (net of any benefits they might provide to the 
system). Ultimately, these charges and payments will 
be established over time between the various parties. 
This market is relatively new and still innovating.

6 Although within each state, specific regions of peak demand growth driven by new developments have remained.

7 Bureau of Meteorology 2011, ‘La Nina reaches its end’, media release, BOM, Canberra, <http://www.bom.gov.au/social/2011/07/lanina-ends/>.



Figure 5: Index (2005–06=100) 
of historical consumption (TWh) 
in NEM states

Source: AEMO (2013b)

For a description of this image please contact paul.graham@csiro.au
Figure 6: Index (2005–06=100) 
of historical peak demand 
(GW) in NEM states

Source: AEMO (2013b)


For a description of this image please contact paul.graham@csiro.au

Greenhouse gas emissions, 
carbon policy and climate 
change vulnerability

DECARBONISING AUSTRALIA’S 
ELECTRICITY SUPPLY 

Greenhouse gas emissions from electricity generation 
in Australia peaked in 2008 at 208 million tonnes 
of carbon dioxide equivalent and were reported at 
191 million tonnes of carbon dioxide equivalent in 
December 2012. A combination of factors led to this 
outcome. From a policy perspective, state-based solar 
feed-in tariffs, energy-efficiency schemes, the RET 
and the Clean Energy Future carbon pricing policy 
were in place. Forced outages at coal plants, lower 
electricity demand contributing to the closure or 
mothballing of some coal-fired plants, and strong 
hydroelectricity supply are also thought to have 
played a part (Figure 7). Because these multiple 
factors occurred together, there is some uncertainty 
and debate about their individual level of impact.

Despite this recent reduction in emissions, the 
electricity sector remains the largest single 
source of Australian emissions, and further 
decarbonisation is required over coming decades 
if Australia is to contribute its fair share to the 
global greenhouse gas abatement task.

For a description of this image please contact paul.graham@csiro.au
Figure 7: Historical 
electricity sector 
greenhouse gas emissions

Source: DIICCSTRE (2013)

CARBON POLICY UNCERTAINTY

In Australian politics there is bipartisan support 
for a 2020 national greenhouse gas emission 
reduction target of 5–158 per cent below 2000 levels 
(or 25 per cent below 2000 levels, if the world agrees 
to a deal capable of stabilising levels of greenhouse 
gases in the atmosphere at 450 parts per million 
carbon dioxide equivalent or lower), but there is no 
bipartisan view on the best set of policy mechanisms 
to achieve this target or on the longer-term emission 
trajectory beyond 2020. Current legislation requires 
emissions be 80 per cent below 2000 levels by 2050. 

Carbon policy targets the generation end of the 
electricity supply chain where it provides a financial 
incentive for investors to change the technology mix 
to favour lower-carbon generation technologies. 
It can also affect the retail price and consequently 
drive behavioural change in customers. Further, 
carbon policy can affect transmission costs in 
cases where it is necessary to have different 
generation locations in order to access or support 
the operation of lower-emission resources.

Uncertainty about carbon policy can delay 
or lead to sub-optimal investment decisions 
for electricity generation (Nelson et al 2011). 
At present, the Large-scale Renewable Energy 
Target, rather than the carbon price, primarily 
drives development of new electricity generation 

8 Australia will unconditionally reduce its emissions by 5 per cent compared with 2000 levels by 2020 and by up to 15 per cent by 2020 if there is 
a global agreement that falls short of securing atmospheric stabilisation at 450 parts per million carbon dioxide equivalent under which major 
developing economies commit to substantially restraining their emissions and advanced economies take on commitments comparable to Australia’s.



capacity, but expectations around carbon policy 
beyond 2020 will increasingly become material 
to investment. Given the electricity sector is the 
largest single source of greenhouse gas emissions 
in Australia, the lack of an explicit, stable, long-term 
decarbonisation signal increases the risk to investors 
of substantial changes in carbon policy during the 
asset’s lifetime or even during its construction.

VULNERABILITY TO CLIMATE CHANGE

The strong impact of weather conditions on the 
operations of the electricity system leaves it especially 
vulnerable to climate change. Climate affects the 
electricity industry at every stage of the supply 
chain. It heavily influences the daily and seasonal 
profile of demand, the efficiency of generation, 
the availability of cooling water or hydropower 
resources, capacity of the network, and expenditure 
on maintenance and storm event damage, among 
many other factors. The reduction in capacity of 
transmission and distribution assets under high 
ambient temperature conditions is particularly 
challenging because it occurs when demand is 
likely to be high as a result of air-conditioner load. 
The potential for more frequent extreme climate 
events in the future, and the inability to predict 
these, is a concern for system reliability and cost.

Shifting attitudes to 
reliability and its cost 

Reliability of supply has always been a goal in the 
development of the electricity system and because 
of the historically prohibitive cost of storing 
electricity, the focus has been on the network being 
able to meet supply during credible contingencies. 
To ensure satisfactory levels of reliability, the 
system must have a level of built-in redundancy to 
allow for failure and outages of parts of the system 
from external factors, such as extreme weather. 
Reliability has become more important over time 
as Australia’s lifestyle and industry have become 
more dependent on electricity (notwithstanding the 
recent uptake of more battery-powered personal 
computing devices). In 2005, New South Wales and 
Queensland increased their reliability standards for 
electricity distribution following extreme weather 
events. These increased standards triggered additional 
network investment to achieve compliance. After the 
electricity price rises that occurred between 2007 
and 2012 (Figure 1) many have questioned whether 
reliability standards are now set too high or too 
prescriptively in these jurisdictions (Wood 2012).

Analysis by the Australian Energy Market Commission 
(2012b) surveyed 1,300 New South Wales customers 
and confirmed that, based on their valuation of 
reliability, there would be some benefits if the level 
of distribution reliability were to be reduced. The 
benefits of reduced investment in reliability would 
be realised in the longer term since expenditure 
to meet the 2005 New South Wales reliability 
standards is already committed. New South 
Wales customers are estimated to save between 
$3 and $15 a year in exchange for an additional 
2–15 minutes of outages a year on average.9

To address the concerns about reliability standards, 
the state and Commonwealth governments agreed 
in principle to implement a national framework 
for transmission and distribution reliability and 
commissioned the Australian Energy Market 
Commission to report on the proposed framework 
(AEMC 2013b), which it completed in late 2013 
(AEMC 2013c). The report provides a set of broad 
principles which state jurisdictions and network 
service providers will consider and further develop. 

9 Individual experiences of outages will vary significantly depending on location and network.



Section 3: Future Grid Forum 
scenario origins and assumptions

In developing the four scenarios it 
was clear to the Forum that: 

..There are some factors that create significant 
uncertainties for the system, but do not alone 
require it to fundamentally change, such as fuel 
price volatility and changes in technology costs. 
..There are some changes that are so significant 
they carry the potential to cause a ‘megashift’ in 
the electricity system. A ‘megashift’ occurs when, 
either incrementally or suddenly, an industry and 
its businesses must be substantially restructured 
to accommodate a new reality. Three potential 
megashifts for Australia’s electricity sector are the 
advent of low-cost electricity storage, sustained 
low demand for centrally-supplied electricity, 
and the need for significant greenhouse gas 
abatement. These megashifts are factored 
into the four scenarios to varying degrees. 
..Consumer engagement with their electricity supply 
has recently increased, but it is uncertain how much 
consumers will want to engage in the future. The extent 
to which consumers engage is an important variable in 
each scenario, ranging from passive to highly engaged. 


General uncertainties

The list of general uncertainties is naturally a 
long one given the complexity of the electricity 
system, but the key uncertainties the Forum chose 
to include in scenarios or sensitivity cases are:

..fuel prices
..carbon and energy policies (targets 
and implementation mechanisms)
..technology costs
..climate change impacts.


FUEL PRICES

Fuel prices can have a large impact on electricity 
generation costs, potentially affecting the wholesale 
electricity price by $20 to $4010 per megawatt 
hour over the long run (Graham et al 2013a). 
In particular, there has been significant discussion 
within the electricity sector about the uncertainty 
around future gas prices in Australia owing to a 
wide variety of influences, including challenges 
in the social acceptance of accessing coal seam 

For a description of this image please contact paul.graham@csiro.au
Figure 8: Future Grid Forum 
scenario development 
framework

10 All projections in this report are in real 2013 Australian dollars.



gas resources where there are existing land use 
activities, the potential for greater east coast 
export price parity in Australia as a result of the 
development of export terminals, and the potential 
global market impact of increased shale gas supply 
in the United States (Wood & Carter 2013).

The fuel cost ranges applied in this report are based 
on ACIL Tasman (2012) and are presented in Figure 9 
for the east coast of Australia. The projections 
assume that price movements for gas are far more 
uncertain than those for coal. It is assumed natural 
gas prices will rise as a result of the east coast 
being exposed to international competition; the 
main uncertainty is in the degree of the increase.

The medium fuel price paths have been applied 
in Scenario 1: ‘Set and forget’ and Scenario 4: 
‘Renewables thrive’. The low fuel price path has 
been applied in Scenario 2: ‘Rise of the prosumer’ 
and Scenario 3: ‘Leaving the grid’ to support the 
economic plausibility of the high use of gas in on-site 
generation expected in those scenarios. A sensitivity 
test was conducted on Scenario 1 to understand 
the impact if the high fuel price path had been 
applied. It found that wholesale electricity prices 
would be around $10 per megawatt hour higher 
and greenhouse gas emissions 40 million tonnes 
of carbon dioxide equivalent higher by 2050 under 
higher fuel prices. This reflects greater use of coal, 
which is more competitive under high gas prices.

Renewables deployment is lower when gas prices 
are high because high gas prices increase the cost of 
managing the variability of some renewable supply 
(unless other options, such as demand management, 
peaking direct-injection coal engines, or storage are 
able to fulfil that role at low cost). Use of storage is 
explored in Scenario 4; direct-injection coal engines 
are included in the modelling technology set, but 
demand management is generally targeted at peak 
demand reduction rather than supporting renewables 
when it is implemented in Scenarios 1, 2 and 4. 
The projected impact of high gas prices on renewables 
is specific to this study, which has assumed gas-fired 
plants are a low-cost source of generation based 
on BREE (2012) (see technology cost assumptions 
below). Were other technologies (perhaps even other 
renewables) able to support variable renewables at a 
similar cost to gas plant, then the price of gas would 
not have such an impact on renewable deployment.

For a description of this image please contact paul.graham@csiro.au
Figure 9: East coast coal and 
natural gas price projections

Source: ACIL Tasman (2012)



CARBON AND ENERGY POLICIES

Australia’s current national emission reduction 
targets are to achieve 5–158 per cent below 2000 
levels by 2020 (or a 25 per cent reduction if global 
action is stronger) and 80 per cent below 2000 
levels by 2050. The legislated 2050 target is 
described by Treasury (2011) as Australia’s fair share 
of abatement in contributing to the global goal of 
limiting average temperature increases to 2 degrees 
Celsius. Stabilisation of atmospheric concentrations 
at 450 parts per million carbon dioxide equivalent 
is estimated to provide a 50 per cent chance of 
avoiding exceeding 2 degrees Celsius and the 
aggregate global emission abatement paths are 
derived on that basis. Stabilisation of atmospheric 
concentrations at 550 parts per million carbon dioxide 
equivalent is estimated to provide a 50 per cent 
chance of avoiding exceeding 3 degrees Celsius.

In determining Australia’s fair contribution to global 
greenhouse gas abatement efforts, there are many 
ways in which it could be assigned: capability (wealth 
and access to abatement options), responsibility 
(contribution to historical emissions), equality 
(recognising an equal right to emit greenhouse gases), 
or access to sustainable development (supporting 
the development needs of poorer countries) (Climate 
Change Authority 2013). Although there are many 
issues of contention, it was not a priority for this 
Forum to challenge any of these concepts or to 
analyse them further. This report therefore relies on 
reinterpreting the existing analysis to understand the 
possible range of carbon prices that the electricity 
sector may have to respond to in the future.

The mechanism for meeting the national emission 
target in Australia is not settled. A fixed carbon 
price was introduced in July 2012 and was designed 
to move to a free-floating carbon price determined 
by the market for emission permits within a 
few years. As at the end of 2013, the in-coming 
government has planned to move to a policy 
called ‘Direct Action’ which includes an abatement 
auction system.11 The Forum does not seek to 
model and evaluate these alternative mechanisms 
in this report, although they would have different 
impacts. Instead, as a necessary simplifying 
assumption, the Forum uses a generic carbon price 
throughout the modelling as a proxy for a range of 
mechanisms that governments might implement to 
send signals to the market to reduce emissions.

The carbon prices presented by Treasury (2011) were 
the most current, with the exception that since that 
work was published it has been acknowledged that 
international carbon prices are weaker than expected 

For a description of this image please contact paul.graham@csiro.au
Figure 10: Treasury (2011) 
and modified Future 
Grid Forum carbon price 
trajectories

11 The government purchases bids for emission abatement up to a given budget or target as opposed to the situation under emission trading where 
the government sets the target and sells permits that sum up to that target. The ‘Direct Action’ policy also excludes using abatement that occurs 
outside Australia, but expands the allowable domestic abatement to include soil carbon.



in the short term, particularly in Europe where 
Australia would first link to international carbon 
prices. To this end, the May 2013 Commonwealth 
Government budget papers updated the series to 
2018–19 to take into account the weaker carbon 
price market. Therefore, the Forum developed two 
modified carbon price paths. All four scenarios adopt 
a modified version of Treasury’s (2011) 550 parts per 
million scenario (Figure 10). A high carbon price 
sensitivity case is also adapted from the Treasury’s 
(2011) 450 parts per million price path. In both cases, 
the carbon price recovers to its previous path.

Recognising that Australia’s carbon price policy 
is not settled, the Forum also explored two 
additional sensitivity cases. The first is no carbon 
price. This is useful as a way of understanding 
the costs of greenhouse gas mitigation and the 
underlying trend in wholesale electricity price 
absent a carbon price signal. The second sensitivity 
case examines an uncertain carbon price case 
which does not assume a single carbon price 
projection, but rather examines how ongoing 
uncertainty across the entire future possible carbon 
price range impacts on the electricity sector.12

TECHNOLOGY COSTS

The Australian Government conducted the first 
Australian Energy Technology Assessment (AETA) 
in 2012, coordinated by the Bureau of Resource 
and Energy Economics (2012). AETA projects the 
cost and performance characteristics (for example, 
capacity factor, efficiency, and carbon capture rate) 
of most large centralised electricity generation 
technologies to 2050. The AETA technology capital 
cost projections13 were developed on the basis 
of a Treasury (2011) 550 parts per million world in 
terms of global greenhouse gas reduction effort. 
Therefore, they provide a reasonably consistent 
technology cost assumption for the Forum’s 
scenarios. For Scenario 4, however, the Forum 
wished to include the possibility of an accelerated 
rate of reduction in the cost of renewable energy 

For a description of this image please contact paul.graham@csiro.au
Figure 11: Alternative 2050 capital cost assumptions for large-scale centralised electricity generation technologies

12 See Graham et al (2013b) for details of how this sensitivity case is implemented.

13 The capital cost of carbon capture and storage technologies shown in Figure 10 does not include the cost of carbon dioxide storage, but this cost is 
included in all modelling.



technologies. The Forum sourced an accelerated 
renewable energy technology cost projection from 
Hayward and Graham (2012) who developed their 
projection for the Australian Energy Market Operator’s 
100 per cent renewables study.14 Both projections are 
shown in Figure 11 for the year 2050. Most cost 
reduction occurs before 2030, after which the rate 
of cost reduction slows as technologies mature.

The AETA does not address on-site generation and 
so the Forum derived its on-site generation cost 
assumptions from the Intelligent Grid Research 
Program, a CSIRO study analysing the value 
proposition for on-site energy in Australia (CSIRO 
2009). The Forum updated the data where new 
information had become available and indeed 
developed two cases: ‘medium’ and ‘accelerated’ 

(Figure 12). The ‘medium’ case is applied in Scenario 1, 
while the ‘accelerated’ case is applied in Scenarios 
2 to 4 to drive the greater adoption of on-site 
generation envisaged in those scenarios. The Forum 
does not impose any specific on-site generation 
targets in the modelling, but rather allows the 
cost assumptions to drive uptake. However, the 
modelling does include some recognition of limits 
to the size of different customer segments.

Given the scenarios use different cost assumptions, 
it is important to recognise that this means the 
financial metrics of each scenario are not directly 
comparable. It is not possible to say, for example, 
that a given scenario is preferable to the others 
because it appears to have lower costs; this may be 
simply a function of the different input assumptions.

For a description of this image please contact paul.graham@csiro.au
Figure 12: Alternative 2050 capital cost assumptions for on-site electricity generation technologies

14 Department of Industry, Innovation, Climate Change, Science, Research and Tertiary Education 2013, 100 per cent renewables study, Commonwealth 
of Australia, Canberra, <http://www.climatechange.gov.au/reducing-carbon/aemo-report-100-renewable-electricity-scenarios>.



CLIMATE CHANGE IMPACTS

The scenario development process acknowledged 
that there is a significant risk that the climate will 
change with or without successful global greenhouse 
gas abatement efforts. The electricity system is 
particularly vulnerable to climate change because 
the weather impacts nearly every aspect of its 
operation, but the technical ability to downscale 
climate changes to changes in annual weather 
outcomes at specific locations remains limited, 
as does the capacity to estimate and collate all of 
the ways in which the electricity system may be 
affected. Consequently, the Forum did not specifically 
include climate impacts in any of its scenarios.

To begin to get a handle on the possible impacts using 
a simplified approach, however, the Forum conducted 
a sensitivity case to provide an indication of how 
climate change might have changed the scenarios if 
it were included. The simplified approach examines 
the cost of building generation and network plant 
to meet a higher peak demand, but does not link 
the peak demand forecast to any specific climate 
change scenario and excludes many other climate 
change adaptations that might be required.

Megashifts

ELECTRICITY STORAGE

Although currently regarded as too expensive for 
large-scale applications, sustained investment 
in materials manufacture and technological 
development could mean electricity storage plays 
a future game-changing role in many aspects of 
the electricity system. For example, it could: 

..support uptake of renewable electricity 
generation by smoothing or shifting the 
timing of generation export to the grid
..manage distribution system peaks and troughs
..give customers a measure of independence 
from the electricity system if they desire it
..give service providers a cost-effective alternative to 
grid connection for some edge-of-grid customers
..support uptake of electric vehicles
..manage integration of all of these.


New business models and ways of operating 
the system could be required for these roles.

The modelling focuses on battery storage because 
batteries suit most applications envisaged in 
the scenarios, but there are many other storage 
technologies that could be viable. The current 
high levels of investment in battery technology for 
various applications, such as electric vehicles, makes 
it reasonable to assume that electricity storage will 
cost less in future, but how much less is uncertain. 
The International Energy Agency (2012) projects the 
cost of batteries for electricity vehicles will halve 
by 2020. Marchment Hill Consulting (MHC) (2012) 
provides a medium, optimistic and pessimistic case 
(Figure 13). The pessimistic case recognises the 
potential for some raw materials (such as rare earths) 
in storage devices to become more expensive. The 
optimistic case includes a greater than 50 per cent 
reduction by 2020 and the medium case lies between 
the two extremes. James and Hayward (2012) applied 
a modelling approach that assumed battery costs 
would be linked to deployment and improvements 
in the costs of intermittent renewable electricity 
generation technologies, such as wind and solar 
photovoltaics. In this case, a 50 per cent reduction 
is not projected to be reached until 2030. Based 
on these studies, the Forum’s modelling assumed 
the cost reduction trajectory shown in Figure 13.

LOW GROWTH OR DECLINING DEMAND 
FOR CENTRALLY-SUPPLIED ELECTRICITY

Over the past century, Australia’s electricity system 
was geared to manage increasing supply to meet 
growing electricity consumption. Switching focus to 
managing slow-growing or declining consumption 
would require a major paradigm shift for the system. 
In particular, lower apparent grid consumption 
caused by greater use of on-site generation has 
significant implications because it means there 
would be less energy required from central sources, 
but it may not significantly reduce the peak 
demand that the system is called on to supply.

Some Australian states have already 
experienced several years of declining centrally-
supplied consumption. While this coincided 
with the global financial crisis and might 
be temporary, there are other drivers that 
suggest that load growth is becoming less 
strongly influenced by economic growth:

..On-site generation, such as solar photovoltaic 
panels, is becoming cheaper (as discussed, this 
reduces the consumption that is visible to the 
centralised electricity supply chain, but may not 
reduce peak demand or total consumption).




Figure 13: Projected 
percentage reductions in 
storage costs and the Future 
Grid Forum assumed cost 
reduction trajectory

..Sustained high retail electricity prices are driving 
more energy-efficient customer behaviour.
..There are structural shifts in the economy towards 
low energy-intensive service industries and 
experiences rather than material-based production 
and consumption of goods and services.
..Energy-efficient appliances and building 
stock are becoming more commonplace.


Lower centrally-supplied electricity consumption 
has the potential to strand some existing electricity 
generation assets or at the very least force a greater 
focus on utilisation of the existing asset base. This is a 
challenge for current business and regulatory models. 
On the other hand, improved energy efficiency is 
also important in limiting increases in electricity 
bills over time, particularly given the need for the 
generation component of electricity tariffs to rise 
as Australia decarbonises its electricity system.

GREENHOUSE GAS ABATEMENT

Despite recent progress in reducing greenhouse 
gas emissions from the electricity sector 
(an 8 per cent reduction from 2008 to 2012), 
the scale of decarbonisation required to meet 
long-term greenhouse gas emission targets will 
demand much greater transformation. Australia’s 
currently legislated 2050 national emission 
reduction target is 80 per cent below 2000 levels.

The starting point for Australia’s electricity sector 
in contributing to an 80 per cent reduction in 
greenhouse gas emissions is that coal and gas fuel 
69 per cent and 19 per cent of Australia’s electricity 
generation respectively, resulting in a highly 
emissions-intensive power supply. Although emissions 
have been declining since 2008, annual greenhouse 
gas emissions in the electricity sector were 
8 per cent above 2000 levels in 2012 and represent 
35 per cent of total national emissions. The transition 
to a low-carbon electricity system will require 
substantial upgrades to and replacements of existing 
infrastructure, supported by sustained investment 
in research, development, commercialisation, and 
deployment of low-carbon technology solutions.

Consumer choices

CSIRO conducted a literature review to ascertain 
consumers’ interest in exploring new contract 
arrangements and making accompanying behavioural 
changes (Boughen et al 2013). There were three key 
findings. These findings are not concrete; consumer 
attitudes may change in future, but for now they are 
a useful guide to how to manage future adoption of 
emerging electricity technologies and relationships. 

First, up until recent price events and solar uptake, 
electricity use was invisible to the residential 
consumer, resulting in a lack of awareness, 
knowledge and incentive to participate. 


For a description of this image please contact paul.graham@csiro.au

Evidence suggests household knowledge of energy 
use is low, particularly about which appliances 
contribute most to bills. This might be a challenge 
since many of the technologies proposed for the 
future electricity grid require residential consumers 
to be much more aware and involved in their energy 
consumption and, in some cases, production. 

Despite this low knowledge base, research shows 
some residential consumers are willing to investigate 
and even try technologies and initiatives once 
the concepts are explained in detail. Residential 
consumers are already expressing interest in 
becoming more aware and taking control of how 
they consume and produce their electricity. While 
many emerging electricity technologies (such as 
smart meters, dynamic pricing, and direct load 
control) initially receive mixed reactions, often 
negative reactions are overcome once the consumer’s 
knowledge of the technology increases and their key 
concerns (such as the health and privacy concerns 
about smart meters, and the impact of dynamic 
pricing on vulnerable households) are addressed. 
That said, residential consumers are sceptical that 
the proposed benefits will be realised and that 
key concerns will be adequately addressed.

Second, despite saying they are willing to change 
their behaviour to reduce their energy bills, many 
residential consumers continue to behave in ways that 
are contradictory to their intent (for example, they 
increase their use of energy-intensive appliances). 
Research suggests that motivations (for example, to 
help the environment) do not necessarily translate 
into behaviour (such as turning off lights or installing 
solar panels) and other factors also come into play 
(for example, social norms, ingrained habits, and 
the extent to which the person believes it is easy 
or difficult to take action). The research showed 
that cost is top-of-mind and is therefore acting as 
both a primary motivator for, and a key barrier to, 
uptake of alternative tariffs and technologies.

Some studies in the literature review suggest that 
consumers do consider other complementary decision 
factors, including reliability, quality, safety, control, 
and environment, and that in some instances these 
factors can be more influential than cost. As an 
example, early adopters of a technology often rate 
other features as more important than cost. It is 
important to note that evidence suggests that an 
individual’s socioeconomic profile is not a consistent 
predictor of attitudes, values and beliefs, but it may 
be an indicator of their capacity to take action in 
the absence of financial support or incentives.

Finally, the literature review suggests that residential 
consumers need information to help them make 
decisions and the quality of information matters. 
Information and feedback need to be clear, 
accessible, appealing, relevant and timely. What made 
implementation programs (explored in the literature 
review) successful includes consumer involvement 
through engagement, education, consumption 
feedback, and supporting technology. 
One of the most vital components of effective 
engagement is trust. Currently, many utilities in 
Australia are not commanding strong public trust 
and so this will be a challenge to overcome.

To explore the role of consumer choice, the Forum’s 
scenarios represent different types of consumer 
attitudes and industry response. In Scenario 1: 
‘Set and forget’, consumers are passive and industry 
responds by providing demand management and 
tariff regimes that require some decisions up front 
but very little engagement afterwards. In Scenario 2: 
‘Rise of the prosumers’, consumers are much more 
active and push service providers to provide them 
with a wide range of active and ongoing choices, 
including diverse on-site generation options (that is, 
the regulatory environment is much the same as in 
Scenario 1, but consumers want more engagement 
in Scenario 2 and are encouraged by lower on-site 
generation costs). In Scenario 3: ‘Leaving the grid’, 
there is no change from current residential tariff 
structures and so poor price signals remain, leading 
to inefficient use of the grid. Increasing unit costs and 
other factors conspire to push consumers towards the 
greatest form of engagement, which is sole reliance 
on their own off-grid supply, with the assistance 
of service producers specialising in those systems. 
Consumer attitudes in Scenario 4: ‘Renewables 
thrive’ lie somewhere between the extremes of 
Scenarios 1 and 2, with good consumer engagement 
and significant uptake of on-site generation and 
demand management, but a stronger reliance on 
the centralised grid because of its high renewable 
content which has strong community support.



OUTCOME OF CONSUMER CHOICES ON 
CONSUMPTION, PEAK DEMAND AND 
ADOPTION OF ON-SITE GENERATION

The result of these consumer choice assumptions 
is the following consumption and peak 
demand profiles for each scenario: 

..The scenario consumer behavioural assumptions 
were partly imposed by and partly projected 
as changes on the existing Australian Energy 
Market Operator’s National electricity forecasting 
report demand projections AEMO (2013b). 
..The imposed assumptions were uptake of demand 
response activities of residential, commercial and 
industrial customers, including air-conditioning 
optimisation for peak reduction, battery 
storage, controlled electric vehicle recharging, 
and extension of industrial peak reduction 
markets. These activities reduce peak demand 
and were applied in Scenarios 1, 2 and 4.
..To determine the impact of these measures, 
the Forum also examined a sensitivity case 
in the form of a ‘counterfactual’: what would 
be the outcome if demand response was 
not deployed across the scenarios?


The Forum modelling projected uptake of on-site 
generation based on applying the technology 
costs discussed in this section. Uptake of on-site 
generation reduces the amount of consumption 
that must be supplied by centralised electricity 
generation (Figure 14). In scenarios where on-site 
generation uptake is high (see Figure 16), this 
significantly reduces the consumption required 
from centralised electricity generation (Figure 15).

For a description of this image please contact paul.graham@csiro.au
Figure 14: Projected 
electricity consumption 
supplied by the grid 
and on-site generation 
(NEM total)



Figure 15: Projected 
electricity consumption 
supplied by the grid 
(NEM total)

For a description of this image please contact paul.graham@csiro.au
For a description of this image please contact paul.graham@csiro.au
Figure 16: Projected share of 
on-site generation (all states)



Up to around 2020, Scenario 3 demonstrates projected 
peak demand without any significant adoption of 
consumer peak demand reduction measures; however, 
Scenarios 1, 2 and 4 do include peak reduction 
measures in their consumer choice assumptions. 
From around 2020, in Scenario 3, a small number 
of consumers begin disconnecting from the grid, 
accelerating rapidly from 2035. This does not represent 
peak demand reduction measures, but rather that 
the peak demand from these consumers is removed 
altogether from the grid. Instead, their on-site 
systems are managing demand and supply balance.


For a description of this image please contact paul.graham@csiro.au
Figure 17: Projected 
aggregate peak demand to 
be met by centrally-supplied 
electricity (NEM total)


Section 4: The emerging issues for 
electricity in Australia 

Implications of shifting attitudes 
to reliability and the potential 
for customer disconnection

As noted, customers have increased the value they 
place on reliability, but at the same time questioned 
whether reliability standards are too high or too 
prescriptive. Part of deploying demand response 
measures to reduce peak demand would necessarily 
also open up the opportunity for customers to opt 
into a more tailored level of reliability. The option 
to participate in demand response effectively allows 
customers to trade off their cost of electricity against 
making their load available for different types of 
curtailment or load shifting during times of network 
stress (for example, off-peak water heating).

The Forum’s proposed Scenario 3: ‘Leaving the 
grid’ imagines a large number of customers taking 
full responsibility for reliably meeting their own 
electricity demand through complete disconnection, 
and deploying on-site generation and electricity 
management systems. Those disconnected would 
not be able to maintain a link to the grid in case of 
back-up because they would have to pay for that link, 
which would void their motivation (independence 
and cost reduction) for being disconnected. 

BUT HOW ECONOMICALLY VIABLE IS 
FULL DISCONNECTION? 

For commercial or industrial customers with sufficient 
roof space, solar panels with batteries might be 
feasible; otherwise micro or cogeneration systems 
utilising gas, biomass, diesel or coal (depending on 
cost and distribution constraints) would also allow 
disconnection. Small-scale engines or turbines are well 
suited to load-following and are a complete technical 
solution, but there are some limitations. First, these 
customers essentially become reliant on another 
type of grid (fuel distribution grids). Second, costs 
may be prohibitive depending on their load profile. 
They would need to size their plant to their peak 
demand. If the difference in their peak-to-minimum 
demand is very large then the plant will achieve 
a low utilisation of capital, which may result in a 
prohibitively high unit cost of electricity. Third, given 
fossil fuel and carbon prices are expected to rise 
over time, plant running costs would be expected 
to increase (for those that are liable for greenhouse 
gas emissions in any given future scheme).

Microgeneration systems also would be 
technically viable options for residential and 
small commercial consumers, but they are 
generally more expensive at smaller scale and 
would be subject to the same limitations.

For Scenario 3: ‘Leaving the grid’, the Forum 
considered solar photovoltaic panels for the 
main on-site electricity source because they 
are most in keeping with the scenario theme of 
independence, particularly for households. The 
major challenge with solar panels would be to 
manage electricity supply from the panels with 
battery storage to cover general variability, non-
daylight load and temporary cloudy periods.

The battery system would need to be sized for all of 
the demand that is non-coincident with solar output 
and also take into account round-trip efficiency of 
70 per cent and 80 per cent useful charge range. 
Hot water heating would be relatively straightforward 
to arrange during the day given it has built-in thermal 
storage, but a more sophisticated demand control 
system would be required to shift the loads of other 
appliances. Ultimately, there would be a limit to 
what can be shifted and any demand control systems 
would need to be included in total system costs.

The battery and solar systems would need to 
be sized to meet daily energy consumption and 
peak load (when most appliances are switched 
on). Households that have large air-conditioning 
systems, pool pumps or other large power 
devices would need larger systems. 



During extended solar panel outages or unfavourable 
weather, it would be cost-prohibitive to rely solely 
on battery storage capacity. Instead, it would make 
sense to rely on some sort of generator using petrol, 
diesel or gas. Households with high power needs 
might factor in being able to use their generator for 
occasional periods where the demand is very high. 
Biodiesel would be a potential solution to maintain the 
environmental values of the installation. Local council 
regulations, however, might prohibit generators if 
they produce significant noise and local air pollution. 

If the consumer also wants to charge an electric 
vehicle, they would need a system capable of 
storing and charging typically an extra 6 kilowatt 
hours a day or have access to public recharging. 
This does not increase the unit cost of electricity for 
the installation but might, if it’s not already doing 
so, press the limits of roof space. For the purposes 
of Scenario 3, modelling allows for the potential 
development of alternative organic or structural 
photovoltaic panels which would increase the surface 
of the house available for electricity generation.

Sensitivity testing of different levels of household 
consumption (Graham et al 2013b) estimates the 
current cost of household disconnection to be 
92–118 cents per kilowatt hour. Based on a number 
of studies discussed earlier, the Forum assumed a 
50 per cent reduction in storage costs by 2030. As a 
result, disconnection is projected to cost 42–53 cents 
per kilowatt hour by 2030. Assuming a 75 per cent 
reduction in costs relative to 2013, by 2050, the cost 
of disconnection is projected to be 20–24 cents per 
kilowatt hour.15 On the basis of these assumptions, 
disconnection will not be economically viable until 
after 2030, but would be before 2050 under retail 
cost projections (discussed in the following section). 

15 Detailed assumptions are provided in Graham et al (2013b).



Implications for costs and electricity bills

NETWORK UTILISATION

Figure 18: Projected 
distribution network 
aggregate load factor 
under the Future Grid 
Forum scenarios

Falling network utilisation as measured by the 
aggregate load factor of the system16 will be a major 
challenge to containing further increases in electricity 
unit costs. Figure 18 shows the trend in distribution 
network aggregate load factor for each of the 
Forum’s scenarios. The main drivers of utilisation 
across the scenarios are the underlying rate of 
growth in consumption and peak demand, whether 
peak demand is managed, the rate of adoption of 
on-site generation, and consumer disconnection. 

In Scenarios 1, 2 and 4, distribution network utilisation 
initially improves because peak demand is reduced at 
the same time as consumption is growing. Electricity 
consumption is growing in all scenarios, at an 
average rate of 0.6, 0.7, 0.3 and 0.4 per cent a year in 
Scenarios 1 to 4 respectively between 2015 and 2050.

From the 2020s, the utilisation rate begins to decline 
as a result of the uptake of on-site generation 
(Figure 16), which decreases the amount of 
consumption that needs to be supplied by the grid.17 

For a description of this image please contact paul.graham@csiro.au
The incidence of declining network utilisation begins 
earliest and the rate is strongest in Scenarios 2 
and 4 because they have stronger uptake of on-site 
generation. Beyond adoption of the peak demand 
response measures already included in Scenarios 1, 2 
and 4, the Forum scenarios do not assume any other 
specific responses to this issue by network owners.

Scenario 3 does not include any peak demand reduction 
measures and this is the major reason for the lower 
utilisation through to 2035. On-site generation also 
plays a role, but its impact is different to the other 
scenarios. When customers in Scenario 3 adopt on-site 
generation they leave the grid entirely so the system 
loses responsibility for both their consumption and 
their peak demand. When the disconnection rate is 
strongest, around 2035, the loss of these customers 
temporarily improves utilisation because those leaving 
the grid tend to be smaller residential and commercial 
consumers who have a higher contribution to peak 
demand. However, as the level of disconnection 
stabilises, the declining trend reasserts itself.

16 This is a simplification of the modelling approach. These are related but different concepts. Network utilisation is the ratio of energy supplied to 
the maximum energy that could have been supplied by the network capacity. The load factor is the ratio of energy consumption to the maximum 
potential energy throughput implied by peak demand. Also, below system-level, utilisation rates will vary considerably by location.

17 On-site generation could also make a contribution to peak reduction through the use of storage technologies or other load-following capability; 
however, the distribution network will still need to build capacity that is capable of providing for events where on-site generation is not able to 
respond (for example, on-site generation is at maximum output or electricity storage is drained).



DISTRIBUTION UNIT COSTS

Figure 19 shows the outcome of the outlook for 
distribution network utilisation on distribution 
unit costs. For simplicity, the analysis here shows 
distribution charges on a per unit of consumption 
(kWh) basis; however, customers will face a mix of 
different tariff structures depending on their load.

Up to around 2025, distribution unit costs are stable 
or declining in three of the four scenarios, reflecting 
the assumed peak demand, on-site generation 
and energy-efficiency customer behaviours, and 
subsequent impacts on network utilisation.

The improving network utilisation up to 2025 does not 
lead to a major reduction in distribution costs because 
investments in network expansion and reliability 
are long-term investments that are paid off through 
regulated returns to network owners over many 
decades. Operating and maintenance expenses during 
the life of the asset add to the costs. Therefore, even if 
future peak demand growth is contained or reduced, 
under current regulatory arrangements previous 
investments in network expansion and reliability 
will place a floor on unit distribution costs for a 

For a description of this image please contact paul.graham@csiro.au
Figure 19: Projected 
distribution system unit costs 
(real 2013 Australian dollars)


considerable time to come. This is not to say, however, 
that peak reduction activities have no benefit under 
current regulatory arrangements. The modelling 
finds that distribution unit costs would be 2 cents per 
kilowatt hour higher on average in Scenario 1 if peak 
reduction measures had not been implemented.

The potential for declining utilisation due to the 
combined impact of energy efficiency and increased 
use of on-site generation seems reasonably plausible 
and to some extent self-fulfilling under current market 
arrangements. High electricity prices encourage 
uptake of energy-efficiency measures and on-site 
generation, which leads to lower consumption. As is 
clear from the Forum modelling, lower consumption 
increases the per unit cost of distribution that 
would be passed through to all users under current 
volume-based tariffs and encourages the further 
adoption of energy-efficiency and on-site generation. 
The decreasing cost of on-site generation technologies 
increases the likelihood of these outcomes.



GENERATION SECTOR COSTS AND GREENHOUSE GAS EMISSIONS

Figure 20: Projected average 
wholesale electricity unit 
costs by scenario and a zero, 
high and uncertain carbon 
price sensitivity on Scenario 1

Fuel costs, technology costs, carbon policy and the 
rate of consumption growth will influence future 
wholesale electricity generation prices. The Forum 
scenarios all include a carbon price consistent with 
Australia participating in global action to achieve 
greenhouse gas reductions that would result in a 
global concentration target of 550 parts per million 
carbon dioxide equivalent. The variation in projected 
wholesale prices that is evident in Figure 20 is 
therefore a function of other factors within the 
scenarios, with the exception of three sensitivity 
cases on Scenario 1: a zero carbon price, a high 
carbon price, and an uncertain carbon price.

The zero carbon price sensitivity case shows the 
projected wholesale electricity price if the carbon 
price were removed from Scenario 1 in 2014. In that 
case, the wholesale electricity price would revert back 
to the level before carbon pricing was introduced, 
just below $40 per megawatt hour and remain at 
that level for several years. The wholesale price level 
of $40 per megawatt hour is not high enough to 
cover the full cost, including returns to investors, 

For a description of this image please contact paul.graham@csiro.au
of any type of electricity generation that could 
currently be built (BREE 2012). Wholesale prices 
can only remain below the cost of new plant while 
the market is in excess supply, which is projected 
to remain a feature of the market until after 2020. 
After 2020, the wholesale price increases to cover 
the level of replacement cost of new plant, which 
is around $70 per megawatt hour; this is above the 
2013 wholesale price inclusive of a carbon price.

Under the uncertain carbon price sensitivity case, a 
carbon price signal is maintained to 2020 given this 
is the period in which there is bipartisan support 
for an emission target, but thereafter the investor 
faces the prospect of a wide range of carbon prices. 
Under these circumstances, the investor must narrow 
its choice of technologies to those that will achieve 
reasonable returns across a number of scenarios, 
rather than to those that will optimise returns for 
a single given carbon price scenario. The result is 
that the wholesale electricity price is projected to be 
17 per cent ($24 per megawatt hour) higher by 2050.18

18 Nelson et al (2010) find an $8.60 per megawatt hour additional cost, but their study was focused on 2020.



Turning to the scenarios that do include a single 
positive carbon price, the initial dip in the wholesale 
electricity price in 201619 in Scenarios 1 to 4 reflects 
the assumption of the shift to internationally 
linked emission trading and the expected initially 
lower carbon price, particularly in Europe which 
would be an early linking partner. The lower 
trajectory of Scenarios 2 and 3 reflects that energy 
consumption supplied by the centralised grid is flat 
or declining in those scenarios (owing to high on-site 
generation), which tends to keep prices lower.

The wholesale electricity price increases the most in 
Scenario 4 where, in addition to a carbon price, there 
is a policy of achieving a 100 per cent renewable 
share in centralised electricity generation (resulting 
in an 86 per cent share of renewable when on-site 
generation is taken into account in total generation). 
Under this policy, the set of allowable technologies 
in centralised electricity generation is gradually 
narrowed over time to only renewables by 2050 as an 
extension of the existing 20 per cent by 2020 target. 
Natural gas is also ruled out in on-site generation, but 
diesel remains permissible because of its flexibility 
in remote and uninterruptible power applications. 
The assumption of cost-effective electricity storage 
supports the high renewable share. Schedulable 
renewables, such as enhanced geothermal systems 
and biomass, also play a role in supporting other 
variable renewable sources, such as wind and 
solar photovoltaic systems. This is similar to the 
results of other studies, such as AEMO (2013a).

The cost of limiting the centralised generation 
technology set to only renewables is a wholesale 
electricity price that is 31 per cent higher than 
Scenario 1 by 2050.20 It is also higher than the 
Scenario 1 high carbon price sensitivity case. The high 
carbon price sensitivity case imposes a carbon price 
that is consistent with global action to achieve a 
450 part per million carbon dioxide equivalent 
concentration target, but does not restrict the 
technology available to do that. Under that sensitivity 
case, the centralised electricity system, given the 
choice, adopts a significant amount of natural gas 
and coal-fired generation with carbon capture and 
storage. These technologies are not emission-free 
like renewables, but have emission factors that 
are quite low, around 0.1–0.2 tonnes of carbon 
dioxide equivalent per megawatt hour compared 
with the 2013 system average of around 1 tonne of 
carbon dioxide equivalent per megawatt hour.

The national emissions target for Australia by 2050 
is an 80 per cent reduction in the 2000 level of 
emissions. In a national emission trading scheme 
there is no obligation that each industry sector 
contributes exactly their proportional share of 
emission abatement towards that target. Rather, 
contribution should be on the basis of marshalling the 
most reductions from the sectors with the lowest cost 
of abatement. The Treasury (2011) found that under 
the 550 parts per million carbon dioxide equivalent 
concentration carbon price path, the electricity sector 
makes a slightly less than proportionate contribution 
(a 77 per cent reduction) to the national target. Under 
the 450 parts per million carbon dioxide equivalent 
price path, the electricity sector makes a greater than 
proportionate contribution (an 87 per cent reduction).

The modelling here finds much the same result 
(Figure 21). Under the 550 parts per million consistent 
carbon price, Scenarios 1 to 3 achieve abatement 
of between 55 per cent and 70 per cent below 
2000 levels by 2050. If a 450 parts per million 
consistent carbon price is imposed on Scenario 1, it 
delivers an 89 per cent reduction by 2050 relative 
to 2000 levels. If, as in Scenario 4, a 550 parts per 
million carbon price and a 100 per cent renewable 
target emission are combined, abatement also of 
89 per cent below 2000 levels by 2050 is achieved.

19 At the time the modelling was conducted, the government had flagged an earlier shift to emission trading, but had not implemented it.

20 This projection is higher than that found in the AEMO (2013a) study; however, AEMO (2013a) is lower for three reasons. The first is it assumed all 
renewable technology could be purchased at the price prevailing in the modelled year. In reality, most plant would have been purchased in previous 
years at higher cost. Second, AEMO (2013a) does not include the cost of transforming from the present system, which would involve implementing 
a price signal for any fossil units built before 2050 to shut down. This price signal may need to be reasonably high given it is likely the capital costs 
of any fossil plant would be regarded as sunk once constructed. Finally, AEMO (2013a) used biomass converted to biogas in peaking plant as back-
up to variable renewables, but Forum modelling finds any available bio-energy resources would be purchased by the transport industry.



Figure 21: Projected 
average wholesale 
electricity unit costs 
and per cent below 
2000 greenhouse 
gas emission 
levels in 2050 by 
scenario and a zero 
and high carbon 
price sensitivity on 
Scenario 1 compared 
to 2013

WHOLE-OF-SYSTEM COSTS

The increasing per unit of consumption cost pressures 
from decreasing network utilisation in the distribution 
and transmission sectors, together with carbon 
policy and higher generation plant replacement costs 
following weak market conditions in the next decade 
in the generation sector, mean that in total the retail 
unit costs of electricity are projected to rise under 
the Forum’s scenarios (Figure 22). All scenarios are 
remarkably similar up to 2030 because those with 
higher transmission and distribution costs (due to 
weak consumption growth causing low utilisation) 
receive an offsetting reduction in generation 
costs which are low under these conditions (a 
greater number of assets with sunk costs generate 
at below long-run marginal cost). The reverse 
occurs under higher utilisation in Scenario 1.

By 2050, however, Scenario 1 has the lowest 
increase in unit costs because its lower growth 
in distribution and transmission costs eventually 
more than offsets the higher cost of generation. 
Scenario 4 has the higher unit retail costs by 
2050 as a result of its high generation costs. Unit 
costs, however, are not necessarily the most valid 
indicator of costs. Unit costs ignore volume and 
scale. An alternative measure is cumulative system 
expenditure (Figure 23). This includes all expenditure 
on capital, operations and fuel in the generation, 
distribution and transmission sectors.21 It also 
includes a cost for off-grid expenditure, such as 
on-costs for ‘smart’-enabled appliances, smart meters 
or other equivalent control and communication 
devices and on-site storage. On-site generation 
appears in ‘generation’ if it is connected and in 
the ‘off-grid’ category if it is disconnected.

21 The calculations ignore the retail sector for this analysis because it is assumed to be a fairly constant value across scenarios. Even in Scenario 3: 
‘Leaving the grid’, retail costs would potentially be substituted with other costs from energy service companies.


For a description of this image please contact paul.graham@csiro.au

Figure 22: Projected unit 
cost of retail electricity 
supply from the centralised 
grid by scenario

For a description of this image please contact paul.graham@csiro.au
Figure 23: Projected cumulative system cost by scenario to 2050


For a description of this image please contact paul.graham@csiro.au

From a cumulative system expenditure point of view, 
Scenario 1 is the lowest cost scenario from 2030 to 
2050. Management of growth in peak demand has 
been important in achieving this result. Scenarios 2 
and 3 result in the highest system cost outcomes. In 
Scenario 2 this reflects that while uptake of on-site 
generation has been optimal for individuals, it 
has caused some duplication in the system since 
generation, transmission and distribution capacity 
must still be developed and maintained for when 
on-site generation needs to be backed up.

In Scenario 3 the high cost outcome reflects the off-grid 
cost of disconnecting and the high growth in peak 
demand for the remaining connected customers, which 
means the system is not significantly downscaled 
even after the significant loss of customers. 

Looking at system costs for Scenario 4 reveals it is the 
lowest-cost scenario during the 2020s and remains 
second lowest for the remainder of the projection period. 
This reflects that Scenario 4 includes both significant 
peak reduction and energy efficiency, which means that 
system investment is kept to a minimum. Costs under 
that scenario only rise above Scenario 1 from 2030 due 
to generation investment to meet the 100 per cent 
renewable target for centrally-supplied electricity.

CUSTOMER IMPACTS

Residential

This analysis highlights the importance of considering 
both unit and total system costs, but to break it down 
further and to understand consumer impacts, the 
Forum considered a residential electricity bill since 
that encapsulates paying a unit price, a given volume 
of electricity consumption, and the opportunity to 
consider on-site generation (Figure 24). It is assumed 
on-site generation, if connected, is sold back to the 
electricity grid at a price consistent with the retail unit 
cost minus retail and distribution cost components 
(and this reduces annual electricity costs). Scenarios 3 
and 4 include their existing assumption of 0.7 per cent 
a year lower electricity consumption per household, 
while Scenarios 1 and 2 have a slower 0.3 per cent a 
year improvement over the current average rate of 
electricity consumption of 6,000 kilowatt hours a year.22

For a description of this image please contact paul.graham@csiro.au
Figure 24: Projected net annual electricity cost (retail bill minus PV export payments plus amortised on-site costs where 
relevant) under alternative scenarios and household types

22 These were based on AEMO (2013). As a guide to potential household electricity consumption, ClimateWorks (2013) recommends 0.7 per cent a 
year as a central estimate within a high energy efficiency scenario of 2.2 per cent a year improvement and a low scenario of 0.8 per cent growth in 
electricity consumption.



The analysis shows that by 2030, the best outcome 
for the residential consumer is to have a reduced 
rate of electricity consumption and either contract 
all of their electricity supply from the grid or 
adopt solar panels if the retail electricity price 
is higher, as is the case under Scenario 4. Under 
all scenarios, there is almost no increase in the 
household electricity bill by 2030 compared with 
today. However, if the residential consumer is 
unable to achieve a high rate of electricity efficiency 
improvement (as in Scenarios 1 and 2), the best 
option for the household is to adopt solar panels 
because this will result in a modest reduction 
in costs relative to retail supply only. Note, the 
difference in owning and not owning connected 
solar panels is not large in 2030 and would depend 
on specific feed-in tariffs secured and the profile 
of household electricity use (as it does now).

By 2050, the projections indicate it is financially 
preferable for all residential consumers to have 
some type of on-site generation rather than 
grid supply only. The lowest cost outcome for 
grid-connected households with on-site generation 
occurs under Scenario 1 followed by Scenario 
4; however, if more households choose on-site 
generation to reduce net electricity bills then the 
assumptions of these scenarios are violated and 
consumers shift into the world of Scenario 2: ‘Rise of 
the prosumer’ where there is much broader uptake 
of on-site generation and subsequent higher unit 
retail costs due to lower network utilisation.

If, however, the assumed 75 per cent reduction 
in battery costs by 2050 emerges, then complete 
disconnection will potentially be a preferable 
option than remaining connected as in Scenario 3: 
‘Leaving the grid’. If, however, those circumstances 
do not arise then, again, remaining connected 
with some on-site generation is the preferred 
outcome. From a big picture point of view, there 
is a sense that, over time, circumstances will tend 
to push customers towards adoption of on-site 
generation and potentially into disconnection, with 
the plausibility of this latter step highly depending 
on costs of storage systems relative to any changes 
in the cost of network connection charges.

Of course, all of the scenarios represent an increase in 
electricity bills by 2050, but does this mean electricity is 
a greater share of our household budget? To determine 
that, the Forum needed to consider whether there 
were compensating increases in income. The most 
appropriate projections of future increases in real wages 
are from the Treasury (2011), which considered how the 
economy grows under a carbon price. In that analysis, 
real wages increased by around 37 per cent to 2050 
under a 550 parts per million consistent carbon price.23

The current share of the electricity bill in an average 
wage is 2.5 per cent. This share slightly improves 
(declines) or is maintained by 2030; however, the 
projected 37 per cent increase in real wages from 
2013 to 2050 is not enough to offset the increases 
in electricity bills to 2050 across all scenarios 
(Figure 25). The future share of the electricity bill 
in the real wage is projected to be 2.3–2.9 per cent 
depending on the scenario (Figure 25).

While the average wage earner is not likely to 
experience significant financial stress as a result 
of increased electricity prices, vulnerable groups 
for whom electricity is a greater share of their 
expenditure and whose income may not keep pace 
with real wages would be more significantly impacted. 
The most vulnerable will be those dependent on 
unemployment programs such as Newstart and 
single parents and pensioners who do not own their 
own home. For Newstart recipients, the current 
share of electricity in their income would be around 
14 per cent at average electricity consumption.

In Figure 25 the Forum examines the pensioner’s share 
of electricity in their income since the future indexing 
arrangements for pensions are more settled. For a 
pensioner, the current share of an electricity bill in the 
pension payment (assuming average consumption) is 
9 per cent and this is projected to be between 8 and 
10 per cent across the scenarios. Welfare recipients 
with large households to support will be worse 
off, while those with lower electricity consumption 
and the capacity and knowledge to invest in energy 
efficiency will fare better. Governments will need 
to consider whether the current form and level of 
social safety net payments is adequate for managing 
the general cost of living, including electricity 
costs, for those at risk of experiencing hardship.

23 Technically, the wages growth projection is an over-estimate because the economic growth modelled by Treasury under a carbon price takes 
into account the cost to the economy of reducing emissions, but not the cost of climate change impacts. Climate change impacts will be partially 
mitigated by the abatement activity, but not reduced to zero, due to the inertia in the climate system and continued emissions along the global 
abatement path.



Figure 25: Residential electricity share of income in 2030 and 2050 by scenario

Commercial and industrial

Electricity price increases will not uniformly impact 
each industrial and commercial sector of the economy, 
but rather will impact the cost of production the 
greatest for those industries with the highest 
electricity intensity. Figure 26 shows how this 
varies across key industry and commercial sectors. 
Manufacturing, which is the most electricity-intensive 
sector, includes food, beverages, textiles, wood, paper, 
printing, petroleum and chemical products, iron and 
steel, and non-ferrous metals, such as aluminium.

Each scenario assumes the commercial sector 
reduces the intensity of its electricity consumption 
through building and equipment energy efficiency. 
In Scenarios 1 and 2, electricity intensity is reduced 
by 6 per cent and 12 per cent by 2030 and 2050 
respectively. In Scenarios 3 and 4, the improvement 
is 14 per cent and 26 per cent by 2030 and 2050 
respectively, based on AEMO (2013b). The projections 
on which the Forum’s scenarios were based did not 
assume any specific industrial energy-efficiency 


For a description of this image please contact paul.graham@csiro.au
measures (AEMO 2013c); however, ClimateWorks 
(2013) has observed that industrial energy efficiency 
has been improving at 1.1 per cent a year and there 
are sufficient opportunities to continue the trend 
until 2020, after which the potential is less certain. 
Continuation of the current trend would imply a 
20 per cent and 26 per cent reduction in industrial 
electricity intensity by 2030 and 2050 respectively.

Small commercial customers have similar cost 
components in their electricity bill as residential 
consumers, but with some differences in network 
and retail costs depending on the supplier. As such, 
changes in residential bills are a reasonable proxy for 
the expected proportion of change in their electricity 
bills. For larger commercial and industrial customers, 
however, their electricity charges are structured 
differently. They have significantly lower retail and 
network costs (per kilowatt hour) in recognition that 
there are significant economies of scale in being 
able to service a single customer who consumes 
several hundred (large commercial) to many thousand 
(industrial) times the volume of a residential or small 



Figure 26: Megawatt hours 
of electricity required per 
million dollars of output by 
industry category

Source: ABS (2013b)

commercial consumer. This means that the costs of 
generation (rather than network and retail) are a 
much stronger determinant of impact on commercial 
and industrial electricity bills—industrial customers 
even more so than large commercial customers.

Figure 27 shows the projected change in commercial 
and industrial electricity bills, inclusive of commercial 
sector electricity intensity improvements.24 

Overall, the projections indicate commercial 
and industrial electricity bills will increase in 
real terms; more so in the period after 2030, in a 
similar outcome to that for residential consumers. 
The Forum cannot know, without examining each of 
the relevant markets (which is outside the scope of 
this study), whether these commercial and industrial 
customers are able to absorb these cost increases.

Industrial customers who were assumed to make 
no changes in electricity intensity of consumption, 
and are the most exposed to generation cost 
increases of approximately 100 to 200 per cent 
across the scenarios, are projected to experience the 
strongest increase in electricity bills. For both large 
commercial and industrial customers, Scenarios 1 
and 4 result in the highest electricity bills because 
these have the greatest increases in wholesale 
electricity generation costs in 2030 and 2050.

In the immediate decades, these customers might be 
eligible for schemes that partially exempt them from 
carbon price components of electricity generation 

unit costs if they are competing with countries 
that have not yet made the same commitment to 
greenhouse gas reduction.25 Also, as discussed, 
the present estimates do not include actions to 
reduce industrial electricity intensity of output, 
for which there is significant potential.

Addressing the risk of declining 
network utilisation 

The Forum scenarios have highlighted the risk that 
network utilisation might decline if consumption of 
centrally-supplied energy is flat or declining while 
peak demand is increasing. Together with the debate 
about reliability standards (discussed earlier) and 
general uncertainty in future demand highlighted by 
the Forum’s scenarios, there is a case for considering 
the future of network investment regulation.

For peak demand, a number of reviews, such as the 
Australian Energy Market Commission’s Power of 
choice in 2012 and the Productivity Commission’s 
Electricity network regulatory frameworks in 2013, have 
recommended measures to reduce the aggregate 
peak demands at the generation, transmission 
and distribution levels. These measures include:

..ensuring there is a competitively neutral 
environment for investment and innovation 
in demand response (including storage, smart 
appliances, advanced metering and various 
types of energy management systems) in order 


24 See Graham et al (2013b) for assumed tariff and electricity consumption.

25 The current policy is called the Emission-intensive Trade-exposed Industry Assistance Package.


For a description of this image please contact paul.graham@csiro.au

Figure 27: Index (2013=100) of projected changes in commercial and industrial electricity bills

to address concerns that current regulations may 
provide unbalanced incentives towards building 
additional network capacity to meet demand
..implementing strategies to allow 
more cost-reflective pricing 
..developing standards and regulations that allow 
the relevant technologies to be integrated
..expanding delivery of information 
which supports market choices.


The forum scenarios highlight the need to accelerate 
the evaluation and, if appropriate, implementation 
of reforms such as these to support peak demand 
reduction. However, electricity market reform in 
Australia is necessarily slow because of the multiple 
jurisdictions involved in decision-making and the need 
for robust information and consultation processes. 
There is a risk that some future potential market 
developments could outpace the market reform 
process, which can only be fully implemented at the 
end of the five-year pricing periods under which 
the current regulation operates. As such, benefits 
of reform can take a long time to flow through.

Besides reducing peak demand, one could also 
consider whether Australia’s system of regulating 
networks may need to change. As regulated 
monopolies, customers in most normal circumstances 
share the risk of under- or over-investment in network 
capacity with the network companies. Under the 
current National Electricity Law and Rules, the risk of 
financial stranding is constrained to circumstances 
where capital expenditure is undertaken above 
regulatory allowances. Network investors receive a 
regulated rate of return on existing capital assets. 


For a description of this image please contact paul.graham@csiro.au

However, given a fundamental assumption of existing 
arrangements—monopoly supply—is potentially 
challenged by increasingly sophisticated on-site 
generation and demand response, a process may 
need to be established to identify changes, if any, 
that might be required to market frameworks.

Some potential options that would 
moderate declining utilisation are:

..even greater reductions in peak demand 
than those already included in the Forum 
scenarios (which were around 10 per cent)
..giving greater consideration to on-site generation, 
which has a lower risk of underutilisation as an 
alternative to network capacity augmentation
..identifying new markets for electricity consumption 
that would support increased throughput.


Electrification of road transport is one potential 
new market that would also contribute to delivering 
more efficient, low-emission transport as the 
emission intensity of electricity declines relative 
to petroleum fuels. The Forum scenarios already 
include additional demand from this sector of 
25–45 terawatt hours, representing 19–37 per cent of 
road kilometres by 2050 (Figure 28); however, even 
greater adoption of road transport electrification 
could be economically viable depending mostly on 
electric vehicle costs and oil prices. It might also be 
appropriate to reconsider under what circumstances 
electric hot water heating should be allowed or 
discouraged. For example, as wind penetration 
increases, its output tends to contribute a greater 
proportion of total overnight generation, which could 
mean electric systems approach the environmental 
credentials of alternative water heating systems.

Finally, to address consumption, it will also be 
important that price signals for energy efficiency 
and the cost of connecting, and payments for 
exporting from on-site generation, are both cost- 
and benefit-reflective so that tariff arrangements do 
not play a distorting role in their rate of adoption.

For a description of this image please contact paul.graham@csiro.au
Figure 28: Projected 
electricity consumption 
from road electrification 
by scenario



Implications of the lack of 
connection between consumer 
prices and service costs 

The Forum believes more cost-reflective pricing 
would provide a number of benefits to the system 
and there is wide scope for change in the residential 
sector where it has primarily been lacking, provided 
consumers are given the information and tools to 
make choices. Table 1 describes four tariff options 
that represent the general range of options available: 
fixed volume, seasonal time-of-use, critical peak, 
and combined capacity and volume. These are not 
the only options, but even this small list highlights 
that moving away from the dominant volume-based 
contract for small consumers would require significant 
education and engagement with consumers, 
including decision-making tools and assistance from 
utilities and intermediaries, such as energy service 
companies. Compared with fixed volume-based 
tariffs, most alternatives offer the consumer better 
price signals of the cost of generation and network 
capacity development, which would ultimately benefit 
consumers through more efficient utility investment.

Table 1: Four general tariff options for consideration

TARIFF TYPE

PRO (INDIVIDUAL)

CON (INDIVIDUAL)

PRO (SYSTEM)

CON (SYSTEM)

Fixed volume-based 
tariff

A single annual cents 
per kilowatt hour fee

Consumer can 
install devices with 
large power (watt) 
rating without 
major (short-term) 
penalties.

Generation 
capacity and 
networks are built 
to accommodate 
power needs 
without an accurate 
view of individual 
consumer’s 
willingness to pay, 
but all consumers 
ultimately foot the 
bill in future years.

It gives a direct price 
signal to manage 
volume. It supports 
signals for lowering 
greenhouse gas 
emissions, which are 
volume-related.

It gives a poor price 
signal for managing 
network capacity 
growth. There can 
be overuse of power 
at peak times during 
the day, leading 
to poor network 
utilisation.

Seasonal time-of- 
use volume-based 
tariff26

Three prices in cents 
per kilowatt hour 
applying per day: 
peak, shoulder, and 
off-peak, varied with 
each season

Consumers who use 
most of their power 
at off-peak times 
can pay less than the 
average price.

Consumers, 
particularly 
low-income groups, 
may lack the 
resources to manage 
their load and pay 
more or experience 
discomfort by 
curtailing the basic 
services they require 
at peak times.

It gives a moderate 
price signal to 
reduce energy 
consumption at 
peak times during 
the day, reducing 
the requirement for 
peaking plant and 
network capacity.

Seasonal peak, 
shoulder, and 
off-peak pricing 
signals remain only 
a proxy for the 
actual daily volatility. 
The price signal 
will only partially 
reflect the true 
level of congestion. 
The price deterrent 
may not be enough 
to reduce peak on 
extreme days. 





26 A less extreme version of this is the current peak and off-peak tariff arrangements in many states. In those cases, the peak and off-peak rates do not 
vary with the season.



TARIFF TYPE

PRO (INDIVIDUAL)

CON (INDIVIDUAL)

PRO (SYSTEM)

CON (SYSTEM)

Critical peak tariff

Two prices in 
cents per kilowatt 
hour: one for most 
hours of the year 
and another for 
designated critical 
peak periods 
nominated via a 
trigger point (e.g. 
temperature)

The consumer only 
needs to consciously 
manage their load 
for a small number 
of days a year.

Design of the tariff 
can be confusing. 
Low-income groups 
may lack resources 
to manage their 
exposure to higher 
prices at extreme 
times or experience 
discomfort by 
avoiding costs. 
There is potential 
for bill shock if 
communication 
of the critical day 
trigger point is 
unclear.

It gives a strong 
price signal for 
reducing loads on 
peak days.

It may lead to a 
relatively volatile 
revenue stream for 
network businesses 
because the number 
of peak days cannot 
be reliably predicted 
each year. Requires 
a communication 
system to advise of 
critical days.

Combined capacity 
and volume tariff27

Part of tariff based 
on power capacity 
used (cents per 
kilowatt) and 
remainder based on 
volume (cents per 
kilowatt hour)

It offers lower costs 
for those with 
fewer appliances 
using high levels 
of power and 
smaller occupancy 
households.

It offers higher 
costs for those with 
multiple appliances 
using high levels 
of power. Many 
consumers will be 
initially unaware 
of the ‘power 
capacity’ concept 
and fail to manage 
their exposure to 
high prices unless 
they have access to 
appropriate tools 
and information.

It gives a good 
price signal for both 
volume and capacity.

There may be 
transaction costs 
in setting up 
capacity rates and in 
education to inform 
consumers so they 
can avoid bill shock.





The Forum believes the electricity sector will 
develop new business models in order to adapt 
to the scale and scope of customer requirements 
envisaged in the scenarios. Currently, the paradigm 
of Australia’s electricity system is a predominant 
one-way flow of power from generation through 
transmission to distribution and finally to the 
customer. Mid-last century, each segment was 
structured as a vertically integrated single entity. 
To some extent, the present trend of a more 
segmented supply chain has eroded (for example, 
retailers and distributers own some generation; some 
generators contract directly with customers), but 
the model of a one-way flow remains dominant.

On-site generation systems, such as rooftop solar, 
which has experienced strong growth in its uptake, 
as well as large discrete on-site generation, present 
a major shift to this paradigm. On-site generation 
systems make the customer the generator and 
can create time-variant, two-way power flows.

If the number of customers using rooftop solar 
or other on-site generation systems continues 
to grow, and these customers remain connected 
to the centralised system only for back-up or 
for opportunities to export their own power 
back to the grid, the current distribution system 
would need to change its focus and become a 
platform and marketplace for local power trading. 

27 Most large commercial and industrial customers are on a tariff of this type.



1950s business model 

--Government-owned
--All services centrally planned 
and implemented by one utility
--Customers consume only


Immediate past model

--Mix of corporatised government 
and private sector utilities
--Generation and retail most 
competitive. Transmission and 
distribution most regulated
--Customers mostly consume only


Possible future 
customer-centric model

--Multiple private parties
--Current roles changed in scope 
and scale
--Customers consume, trade, 
generate, store and charge


Figure 29: Evolution of business models: what’s possible? 

Integrating a large number of solar systems with 
the grid may not require significant coordination 
or regulation if there are contracts that recognise 
the value to all parties and appropriate and 
consistent standards for voltage control and 
communication.28 Electricity distributors face 
significant technical challenges from large 
commercial and industrial-scale on-site generation 
units and clusters of generation units because it 
is much more likely that their net supply to the 
distribution network could at times exceed local 
demand. These circumstances could push beyond 
the tolerances of the current management systems. 

If on-site generation becomes the norm (as is 
considered in some of the Forum’s scenarios), 
retailers might compete to provide the best export 
price for customers’ generation exports. Given the 
reductions in legislated feed-in tariffs of the past 
three years, solar power might initially struggle to 
live up to expectations that it will reduce net energy 
bills. Feed-in payments to customers will vary over 
time according to market and policy changes.

Customers will have strong incentives to use as 
much of their own locally produced power as 
possible so as to avoid exposure to the retail 

28 Standard 4777 provides for various network management protocols and advanced power quality functions. While increasing voltage is a concern for 
solar photovoltaic panels, the standard also envisages that management of electric vehicles will require similar coordination and management of 
under-voltage as a result of their charging.


For a description of this image please contact paul.graham@csiro.au

electricity price, which is currently five times 
greater than the solar panel export price in some 
states.29 This incentive will strengthen if:

..export prices are unattractive for new connections
..solar panels continue to come down in price
..residential- and commercial-scale storage 
becomes more economically viable
..demand management systems are available 
to shift power use to better match solar 
panel or other on-site generation output
..lower-cost, non-solar on-site generation 
options, such as fuel cells, become available. 


The electricity sector can learn a valuable lesson in 
tailoring contracts from the telecommunications 
industry. The path from a one-size-fits-all landline 
telephone system to a smorgasbord of mobile and 
associated data and entertainment services was (and 
to some extent remains) challenging. There were bill 
shocks from a lack of communication when customers 
exceeded their agreed limits on mobile and data 
plans. Infrastructure development couldn’t keep pace 
with adoption of mobile and data services, resulting 
in poor quality services to some customers (ACMA 
2011). Some retailers’ reputations were damaged, 
and some hardware providers lost significant market 
share when they failed to anticipate the importance 
of data services, accessible interfaces and the merging 
of social and commercial functionality (Rushe 2013).

In learning from other sectors, electricity providers 
will need to accurately predict which services other 
than electricity might become essential to provide 
to customers. It will be crucial to determine an 
appropriate rate of smart meter (or an alternative, 
more advanced customer interface) roll-out, matching 
the pace, scale and model in which consumer 
segments will want to transition from a standard 
electricity service to the kinds of alternative tariff 
structures, demand management, and local generation 
options that are becoming increasingly feasible. Those 
retailers who go several steps beyond providing basic 
electricity are typically referred to as ‘energy service 
companies’. These companies provide the services 
that electricity enables, such as air-conditioning, 
lighting, cooking, heating, and entertainment and 
management services like metering, load control, 
and aggregation and data analytics. Some electricity 
retailers in Australia are evolving to provide energy 
services, but will face competition from new 
entrants and other business models in the future.

A major cautionary note in this discussion about 
service and price customisation is that any new tariff 
system will likely create ‘winners’ and ‘losers’. For 
retailers and energy service companies to offer a new 
deal to customers there must be benefits to both 
parties. The structural inertia in the electricity system 
means there are currently no major actions customers 
can take to receive a large discount on their electricity 
costs other than to reduce their consumption volume. 
Reducing their peak load will benefit the system 
the most if it is in a location where peak loads are 
currently constraining the system. With recent 
investment in system capacity and reduced peak 
demand, those opportunities and locations are fewer.

Taking into account this system inertia, the Forum’s 
modelling showed that a major peak reduction 
program would reduce system costs in the long term 
by an average of 2 cents per kilowatt hour (Graham et 
al 2013b). This represents the value spread across all 
customers, but those directly contributing could be 
allocated greater discounts and indeed would expect 
such a discount in exchange for their participation.

Price deregulation offers the best opportunity for 
customers who place least demand on the system to 
be rewarded with lower costs. Under deregulation, 
retailers and energy service companies can realign 
electricity tariffs to better reflect the costs of meeting 
each customer’s needs. So customers who demand 
less pay less. Customers who place greater demands 
on the system (by using very large air-conditioning 
systems or other equipment at peak times, for 
example) may still be cross-subsidised to some 
extent depending on whether cost-reflective pricing 
is voluntary or not. An adjustment and education 
process would assist in deriving the most benefit 
from deregulation so that customers have time and 
opportunity to understand how their power use 
affects the system, when they use their power, and 
the available options for managing their power use. 

There is a significant risk that not all customers will 
equally engage and capture the available benefits. 

29 Solar panel feed-in prices applicable in 2013 by state compared with an average national retail electricity price of 25 cents per kilowatt hour in 
2012–13: QLD and Victoria 8 cents per kilowatt hour, South Australia 9.8 cents per kilowatt hour, Western Australian (based on Synergy) 8.85 cents 
per kilowatt hour, New South Wales voluntary retailer payments 5–8 cents per kilowatt hour based on advice to government published at 
<http://www.myenergyoffers.nsw.gov.au/useful-information/solar-feed-in-tariffs.aspx>. 



Customers will need to have the time and motivation 
to engage, and become better informed and 
sufficiently energy literate to navigate and understand 
all of the options that might emerge. Those who 
don’t will miss benefits. While industry must lead the 
engagement process, government will have a role 
in addressing equity issues for vulnerable groups. 

In a similar way to how Australians think about the 
road network, electricity customers have grown up 
with the idea that electricity is an essential service 
and should largely be provided to all at a similar 
price, particularly at the residential level. But this 
notion is no longer relevant. While changing the 
tariff system will bring about ‘winners’ and ‘losers’, 
the current one-size-fits-all system is already doing 
just that by offering an ever-increasing amount of 
opportunities for individual customers to use the 
electricity system in radically different ways from 
each other. In fact, the current system could deepen 
inequity over time. Therefore, concerns about future 
‘winners’ and ‘losers’ should not halt the transition 
to more cost-reflective tariff structures, particularly 
if education and measures for protecting vulnerable 
customers are well planned and executed.

Implications of greenhouse 
gas abatement and carbon 
policy uncertainty

Achieving long-term clarity on the electricity system’s 
greenhouse gas abatement task will be important 
for efficient electricity generation investment 
decision-making. The life of a power plant is between 
20 and 60 years or seven to 20 election cycles. Once 
the plant is built, if market conditions change for the 
worse, there is no way to recoup losses; the plant 
cannot be moved to a more favourable market or 
scrapped for a reasonable return. Carbon policy 
therefore represents a huge risk for investors in 
electricity generation. The effects of this risk are 
that finance will cost more and investors will choose 
whichever technology offers the best return across the 
widest range of possible policy outcomes rather than 
the least-cost technology—and both of these effects 
manifest as higher electricity prices to customers. 
The Forum’s modelling has estimated that the 
sub-optimal investment resulting from ongoing 
carbon policy uncertainty, while having limited impact 
in the short term while investment requirements 
are low, could result in wholesale electricity prices 
by 2050 that are $24 per megawatt hour higher 
than they would be in an environment of policy 
certainty. While this discussion has focused on new 
plant investment, upgrades to and maintenance 
of existing plant would also be expected to be 
delayed under carbon policy uncertainty.

Implications of the electricity 
system’s vulnerability 
to climate change 

The carbon prices applied in the quantitative 
modelling for the Forum are broadly consistent with 
those that would be required to achieve stabilisation 
at 550 parts per million carbon dioxide equivalent. 
This global greenhouse gas concentration target 
most closely matches the current level of commitment 
expressed by various countries, but is inadequate 
to limit global average temperatures rising no more 
than 2 degrees Celsius. Instead, it is estimated that it 
will deliver a 50 per cent chance of limiting average 
global warming to around 3 degrees Celsius above 
pre-industrial levels. Under this outcome, there 
are significant risks to species and ecosystems. 
More pertinent to the electricity sector, coastal 
infrastructure would face significant risks, including 
frequent or permanent coastal inundation for parts 
of the Australian coastline. There would also be a 
substantial increase in extreme weather across the 
nation (Treasury 2011; Climate Change Authority 2013).

In this context, the electricity sector is becoming 
increasingly interested in climate change impact 
and resilience planning. Understanding these 
climate impacts is still in its infancy, but preliminary 
modelling indicates it could cost an additional 
2.8 cents per kilowatt hour by 2050 to adapt the 
current electricity supply chain to climate change.



Section 5: A potential path forward

The Forum’s proposed framework 
for evaluating outcomes

How much any of these issues and their 
outcomes matters is directly linked to how 
much value people place on them. 
The Forum therefore found it useful to develop 
a framework of five key performance indicators 
for evaluating electricity sector outcomes 
for Australia. This framework focused the 
Forum’s deliberations and could be a useful 
tool for future electricity sector analysis.

Table 2: Future Grid Forum’s proposed key performance indicators

KEY PERFORMANCE 
INDICATOR

DEFINITION AND EXPLANATION

Whole-of-system cost

The total cost of electricity consumed by end-users, inclusive of generation, distribution, 
transmission, retail and any on-site costs that the end-user incurs, in order to obtain the 
desired services that electricity enables

For this indicator, ‘cost’ is used instead of ‘price’ because prices are not always cost-
reflective and users can adopt energy-efficiency measures to reduce their exposure 
to prices (sometimes at a cost) to achieve the same level of services. This indicator 
emphasises ‘efficiency’, but the Forum also considered whether ‘affordability’ might be a 
better higher level indicator for the system. 

‘Affordability’ is a more accurate measure of customer welfare because incomes of 
some groups could rise to offset any cost increases. The Forum concluded, however, 
that the electricity system could not be designed to achieve affordability. The electricity 
sector cannot control incomes, income distribution, and assistance to vulnerable 
groups; these are government responsibilities in managing the economy as a whole. 
The electricity sector can only make the whole-of-system costs as low as possible to 
support affordability.

Reliability

The extent to which the supply and quality of electricity is maintained at a given level

At the macro level, Australia’s electricity supply is generally reliable and Australians 
organise their commerce and lifestyles based on this reliability. At a technical level, 
there are standards for reliability which the different parts of the electricity supply 
chain are responsible for achieving. Importantly, in addition, customers in Australia 
have always been proactive in tailoring their own level of reliability, using methods as 
simple as keeping a stock of candles or as sophisticated as maintaining their own on-site 
uninterruptible power supply system.







KEY PERFORMANCE 
INDICATOR

DEFINITION AND EXPLANATION

Greenhouse gas 
emissions

Emissions from the electricity sector contributing to climate change

The electricity sector produces more greenhouse gas emissions than any other sector in 
Australia’s economy. As such, the sector recognises that while it is not solely responsible 
for greenhouse gas emission reduction, it does have a key role to play in any national 
greenhouse gas abatement effort. Existing national emission targets are one measure of 
the level of abatement the electricity sector may be set to achieve; however, to achieve 
emissions reduction in a cost-effective manner, the sector might deliver more or less 
than its proportional share of abatement depending on the sector’s relative abatement 
costs.

Greenhouse gas reduction presents a specific challenge to how the electricity sector 
operates. Other environmental impacts of its operations are also important, but are 
dealt with by working within other existing environmental management legislation, 
which applies to all sectors. 

Greenhouse gas emissions are typically measured as tonnes of carbon dioxide equivalent 
(tCO2e).

Service and price 
customisation

The degree to which customers can access an electricity contract that matches the electricity 
supply and other services they need and want, and the degree to which the price they pay 
for this contract matches the actual cost the services impose on the system 

Australia currently has limited service and price customisation in electricity contracting: 
there are different contract offerings for each of the residential, commercial, rural and 
industrial customer segments and further choice within those offerings, but consumers’ 
needs are becoming increasingly sophisticated. Many now require a contract that 
includes terms of supply to obtain electricity from their retailer as well as terms to export 
their own generated electricity. Customisation could go further, but for a variety of 
reasons the price charged for the service is not always reflective of the cost of supplying 
the service. Pricing in the electricity system is currently regulated in all states except 
South Australia and Victoria. With other states now considering price deregulation, 
the scope for electricity sector utilities to tailor services and prices may expand, but 
customer desires will ultimately drive this. 

Resilience

The ability of the electricity system to recover from and adapt to shocks such as those from 
technological, market, social, and environmental changes

During the second half of the twentieth century, price and electricity mix were relatively 
stable within the Australian electricity system because of a strong reliance on abundant, 
low-cost coal resources and centralised electricity generation technologies. These 
circumstances contributed to the economic competitiveness of Australia’s industrial 
sector and the lifestyles of Australians. In the first half of the twenty-first century, 
changing circumstances, such as the need to reduce greenhouse gas emissions, higher 
centralised electricity prices, and the emergence of on-site electricity generation 
technologies, have meant that some characteristics of Australia’s electricity system 
that were formerly strengths have become vulnerabilities. Current disruptors to the 
system could potentially strengthen resilience because they create greater diversity of 
supplies if well managed. Valuing resilience and flexibility in the electricity system would 
mean avoiding ‘technology lock-in’ and having transition paths available when events 
challenge the incumbent business model.







APPLYING THE FRAMEWORK

The Forum recognised that while each of these key 
performance indicators is desirable, they do not 
perfectly align and this makes setting goals and 
objectives for the electricity system challenging. 
Trade-offs among potential outcomes will be 
necessary. For example, to achieve greater reliability, 
resilience and greenhouse gas reduction, customers 
would need to incur higher costs. That said, some 
performance areas will partially achieve or reinforce 
others. For example, greater customisation of the 
services customers receive and the prices they pay 
would improve whole-of-system costs per user by 
better matching system investment to willingness to 
pay (although this process would necessarily result 
in some customers paying more if they are currently 
being cross-subsidised under existing arrangements), 
while greater system redundancy would partially 
achieve both system reliability and resilience. 
The Future Grid Forum did not seek to determine 
the best trade off of the key performance 
indicators. The best balance and how to achieve 
it will be different for each stakeholder in the 
sector depending on their individual perspectives 
and resources. The Forum’s purpose was to 
highlight these trade-offs and potential alternative 
outcomes under four future scenarios. 

Impacts by segment and scenario

The degree to which each of the existing and future 
segments of the electricity supply and end-use chain 
will need to change is not equal across the segments 
or scenarios. Scenario 1: ‘Set and forget’ represents 
the least amount of change across the scenario 
set. Customers increase their level of engagement 
when selecting new tariffs, but largely disengage 
afterwards. Retailers and distributers extend the 
variety of tariff structures they offer and administer. 
Increased metering services are required to implement 
some new tariffs and demand management schemes; 
however, continuous communication with the 
customer via interfaces is generally not required. 
Storage becomes prevalent in household energy 
management and electric vehicles emerge as a 
genuine alternative to internal combustion engines, 
but only where convenient. The biggest generation 
changes are for gas-fired power, which expands 
substantially in centralised and on-site generation, 
reducing coal-fired power. Renewables also expand.

In Scenario 2: ‘Rise of the prosumer’, metering and 
energy service companies play a much bigger role in 
facilitating higher levels of consumer engagement 
and on-site generation. This scenario would have the 
greatest need for information and communication 
technologies because of the high degree of connected 
customers engaging in demand management and on-
site generation systems. Electric vehicles are also more 
prevalent. Distribution and transmission companies 
are heavily affected because they see a substantial 
decline in system utilisation via reduced grid-supplied 
consumption without a fully compensating drop 
in peak demand. The market operator faces long 
periods of managing systems in excess supply. Gas 
and renewable generators, both centralised and 
on-site, are again achieving higher market shares.

In Scenario 3: ‘Leaving the grid’, there are very 
few segments of the electricity sector that are not 
heavily affected either by new opportunities or 
challenging changes to established business models. 
Distribution and transmission companies would 
face similar utilisation problems to those in Scenario 
2. Customers disconnecting from the grid will 
experience significant change as they more closely 
manage all aspects of their supply and energy use, 
as will the service companies offering their services 
to support them. Disconnected customers require 
very helpful interfaces to manage their system, but 
there is less need for communication systems on the 
grid. Storage is a key enabler of disconnection.

In Scenario 4: ‘Renewables thrive’, distribution 
and transmission companies will still face the 
lower utilisation issues of Scenarios 2 and 3, but 
to a slightly lesser extent because centralised 
power plays a stronger role. Under this scenario, 
the transmission system in particular may need to 
undergo the largest spatial development in order 
to accommodate the connection of many more 
renewables. Natural gas generation does not undergo 
the large increase seen in other scenarios because 
it is being phased out in centralised supply (along 
with coal). Regulators may need to consider and 
implement changes to the market rules in order to 
accommodate a high penetration of renewables. This 
scenario represents the biggest growth for electric 
vehicles and storage, which becomes a dominant 
technology throughout the system. Information and 
communication systems are required to support 
customers and to coordinate on-site generation, 
but to a lesser extent than in Scenario 2. 

These impacts are summarised in Table 3.



Table 3: Summary of current and future supply chain segment impacts by scenario

STAKEHOLDER

Scenario 1:
‘Set and 
forget'

Scenario 2: 
‘Rise of the 
prosumer’

Scenario 3: 
‘Leaving the 
grid’

Scenario 4: 
‘Renewables 
on tap’

Residential consumer

Modest change


Substantial change


Vastly different


Significant change


Commercial or industrial customer

Modest change


Substantial change


Vastly different


Significant change


Retailer

Modest change


Substantial change


Vastly different


Significant change


Distribution

Significant change


Substantial change


Vastly different


Substantial change


Transmission

Significant change


Substantial change


Substantial change


Substantial change


Generation and transmission system 
operators

Significant change


Substantial change


Substantial change


Vastly different


Energy service companies

Modest change


Vastly different


Vastly different


Substantial change


Metering services

Significant change


Vastly different


Substantial change


Vastly different


Centralised generator – coal

Substantial change


Vastly different


Vastly different


Vastly different


Centralised generator – gas

Vastly different


Vastly different


Vastly different


Modest change


Centralised generator – renewable

Modest change


Significant change


Significant change


Vastly different


On-site generators

Modest change


Substantial change


Vastly different


Significant change


Storage technology providers

Significant change


Substantial change


Vastly different


Vastly different


Electric vehicle providers

Significant change


Substantial change


Substantial change


Vastly different


Information and communication 
technology

Modest change


Substantial change


Significant change


Significant change






KEY: 

Modest change 
= Modest change, manageable within existing structures and business models

Significant change 
= Significant change; some new activities emerge but within existing structures

Substantial change 
= Substantial change where new business models and market structures are required

Vastly different 
= Vastly different from today; most existing activities and business models completely change



Proposed options for addressing 
the issues identified in the 
scenario modelling

The Forum identified options for positioning 
the electricity sector to most effectively plan 
and respond to the issues explored in the 
scenario modelling (Table 4). 
The proposed options are intended only to set 
out broad principles for consideration. Further 
conversations among all stakeholders will be 
necessary to achieve detailed understanding 
and consensus within the Australian community. 
The options are not mutually exclusive; given it 
is not possible to predict which scenario events 
will occur and in what combination, the options 
could be combined or implemented in parallel.

Table 4: Summary of proposed options for addressing the major issues identified in the Future Grid Forum’s modelling

ISSUE

CHALLENGES

RISKS AND BARRIERS

OPTIONS FOR MANAGING 
THE CURRENT TRANSITION

Investment 
in new 
generation

Wholesale electricity 
generation prices are 
projected to remain below 
that which would be required 
to build new plant and 
recover a reasonable return 
on investment until the 
early 2020s.

Wholesale prices need 
to increase from around 
$40/MWh (4 c/kWh) in 2013 
(excluding the carbon price) to 
around $70/MWh (7 c/kWh)30 
(excluding any future carbon 
price or equivalent mechanism) 
to be viable for new plant.

Investment may be slow to 
respond when new plant is 
needed after a long period 
of low prices.

Government

Maintain existing generation 
market arrangements which 
will allow the wholesale 
electricity prices to rise once 
the market supply and demand 
balance tightens and in 
response to carbon policy.

Australian Energy 
Market Operator

Continue to monitor 
generation capacity needs and 
continuously improve demand 
forecasting to support its 
annual Electricity statement of 
opportunities report.

Managing 
peak demand

Limiting growth in peak 
demand is projected to save 
2 c/kWh each year on the 
costs of electricity distribution 
between 2020 and 2050.

Peak demand has declined 
recently in some states and 
its future rate of growth is 
uncertain. If peak demand 
growth recovers in the future, 
it may contribute to declining 
network utilisation.

The majority of small 
commercial and residential 
consumers remain on 
volume-based price contracts, 
have limited knowledge of 
alternative options, and do 
not have access to more 
sophisticated metering. 
Therefore, there is limited 
infrastructure, knowledge 
or incentives to reduce 
peak demand at present in 
these states.

Several peak demand 
reduction actions have 
already been highlighted 
in existing reviews, 
such as Power of choice. 
Reform is challenging in a 
multi-jurisdictional policy 
environment.

Government and regulators

Remove remaining barriers 
to introducing cost-reflective 
pricing in the small commercial 
and residential sector so that 
consumers can receive the 
correct signal for the cost of 
peak power use.

Accelerate the task of 
evaluating and implementing 
other appropriate responses 
to encourage peak 
demand reduction from 
existing reviews.

All stakeholders

Raise consumer awareness 
about the benefits of peak 
demand reduction and cost-
reflective pricing. If adoption 
of cost-reflective tariffs is not 
widespread, then the system 
benefits may be minimal.





30 All prices and their percentage changes are in real terms.



ISSUE

CHALLENGES

RISKS AND BARRIERS

OPTIONS FOR MANAGING 
THE CURRENT TRANSITION

Increased 
on-site 
generation

On-site generation is projected 
to reach 18–45 per cent of 
total generation by 2050. 
This leads to a decline in 
network utilisation that is not 
driven by a lack of effort in 
managing peak demand, but 
rather a shift in the source of 
electricity generation from 
the grid to the user.

If on-site generation 
and demand response 
technologies reach a 
significant share, the model 
of regulating networks 
as monopoly suppliers of 
reliable electricity might 
require a different approach.

Regulators

Encourage network businesses 
to investigate alternative 
network development and 
asset management strategies, 
including market transparency. 
Planning will need to be 
flexible to changes in future 
use and mitigate the potential 
for future reductions in 
network utilisation while 
maintaining agreed levels 
of performance.

Government

Establish processes to identify 
the changes, if any, that 
might be required to market 
frameworks in light of this 
issue and other megashifts 
examined in this report.

Disconnection 
from the grid

Disconnecting from the grid 
as a residential consumer is 
projected to be economically 
viable from around 2030 
to 2040 when independent 
power systems are expected to 
be able to match retail prices 
of 35–40 c/kWh as battery 
costs fall.

Current costs of 
disconnecting are estimated 
at 92–118 c/kWh (around four 
times 2013 retail prices).

If there is a significant share 
of disconnected customers, 
this would challenge existing 
business models.

The cost of small-scale 
generation and storage 
technologies are critical, but 
future cost projections are 
uncertain.

Industry

Innovate to provide optimal 
business models for on-site 
generation and system 
operation.

Government

Consider how and where to 
apportion relevant costs.

Expand the Australian Energy 
Technology Assessment 
process to include small-scale 
generation and storage 
technologies.







ISSUE

CHALLENGES

RISKS AND BARRIERS

OPTIONS FOR MANAGING 
THE CURRENT TRANSITION

Rising 
residential 
electricity 
bills, but 
stable as 
a share of 
income

As a result of increasing 
whole-of-system costs, by 2030 
residential electricity bills are 
projected to be 2–9 per cent 
above 2013 levels.

Some vulnerable residential 
consumers, for whom 
electricity is a large 
component of their overall 
expenses, could experience 
some hardship.

However, the combined 
effect of adoption of energy 
efficiency, on-site generation, 
and general wages growth 
means, for the average wage 
earner, the electricity share 
of income is projected to be 
slightly lower than 2013 in 
2030 and return to similar 
levels by 2050 (between 
9 per cent below, and 
6 per cent above, 2013 across 
the scenario range).

Some low peak 
demand-to-consumption 
ratio households may be 
cross-subsidising high peak 
demand-to-consumption 
ratio households under 
current tariff structures.

Retail unit costs (expressed in 
cents per kilowatt hour) may 
be less relevant over time 
as a measure of expected 
costs due to use of on-site 
generation, energy-efficiency 
opportunities, alternative 
tariffs, and wages growth.

Government

Review electricity bill 
assistance for low-income 
and vulnerable customers, 
including the state-based 
energy concession schemes.

Move to greater retail 
deregulation to support 
efficient price signals for 
electricity system investment 
(for suppliers and consumers 
alike) and reduce the degree of 
consumer cross-subsidisation.

Ensure market structures 
facilitate cost-effective energy 
efficiency adoption.

Residential consumers

Review any new tariff 
structures and government 
support schemes to minimise 
electricity bills. Manage 
both peak demand and 
consumption to offset any unit 
cost increases.

Large 
commercial 
and industrial 
customers’ 
electricity 
costs

As a result of their relatively 
strong exposure to costs 
of generation, which are 
projected to increase to 
achieve greenhouse gas 
emission reduction (see next 
point), large commercial 
and industrial customers are 
expected to experience an 
increase in electricity bills, 
primarily after 2020.

By 2030, large commercial 
customers who adopt 
energy-efficiency measures are 
projected to limit the increase 
in their electricity bills to 
1.1–2.2 per cent a year.

Industrial customers (assuming 
no change in electricity 
efficiency) could face an 
increase in electricity bills 
of between 1.6–3.0 per cent 
a year to 2030 across the 
scenario range.

The manufacturing sector 
(comprising food, beverages, 
textiles, wood, paper, 
printing, petroleum and 
chemical products, iron and 
steel, and non-ferrous metals, 
such as aluminium) is the 
most exposed to increasing 
electricity prices in its costs 
of production.

Australian industries 
are competing against 
countries that have 
different greenhouse gas 
reduction policies.

Government

Review arrangements to 
support the competitiveness 
of Australian export-exposed 
energy-intensive industries. 

Ensure market structures 
facilitate cost-effective energy 
efficiency adoption.

Commercial and industrial 
customers

Implement cost-effective peak 
demand and consumption 
management opportunities to 
offset any unit cost increases.







ISSUE

CHALLENGES

RISKS AND BARRIERS

OPTIONS FOR MANAGING 
THE CURRENT TRANSITION

Electricity 
sector 
emissions

Across the scenarios, 
the electricity sector 
is projected to achieve 
greenhouse gas emission 
reduction of 55–89 per cent 
below 2000 levels by 2050. 
This is reasonably consistent 
with the currently legislated 
national greenhouse gas 
emission reduction target of 
80 per cent below 2000 levels 
by 2050.

To achieve this emission 
reduction, wholesale 
electricity unit costs increase 
from approximately $60/MWh 
in 2013 to between $113/MWh 
(11.3 c/kWh) and $176/MWh 
(17.6 c/kWh) in 2050. Against 
this cost, the benefits of 
avoided climate change were 
not estimated (however, see 
‘Climate change adaptation’ 
below).

The cost of flexible 
generation (such as gas), 
various types of storage, or 
demand management to 
support the variable output 
of some renewables will be 
an important determinant of 
costs of abatement.

Government

Continue to support programs 
for assessing, researching, 
developing and demonstrating 
low-emission electricity 
generation technologies.

Carbon policy 
uncertainty

The wholesale electricity 
price is projected to be 17 per 
cent ($24/MWh or 2.4 c/kWh) 
higher by 2050 if long-term 
carbon policy uncertainty is 
not resolved.

Uncertain carbon policy 
means that plant investment 
is delayed and is dominated 
by a narrower range of 
electricity plant types which 
are able to partially mitigate 
against carbon policy risks to 
projected rates of return.

Government

Develop bipartisan carbon 
policy relating to the targets 
for each decade to 2050 
and the policy mechanisms 
that will be implemented to 
achieve them.

(While not specifically 
modelled, similar investment 
risks and policy remedies 
apply to the Renewable 
Energy Target.)

Climate 
change 
adaptation

Where the risk of climate 
change results in networks 
building to a higher 
probability of extreme peak 
demand events, then unit 
electricity costs are projected 
to be 2.8 c/kWh higher on 
average each year between 
2025 and 2050. Impacts of 
extreme weather generally and 
costs of other electricity sector 
climate change adaptations 
were not estimated, but are 
also very relevant.

The electricity sector is 
particularly vulnerable to 
changes in climate because 
climate affects every aspect 
of its operation, from the 
efficiency of generation and 
transmission through to the 
profile of demand.

Industry and regulators

To support efficient investment 
choices, develop consistent 
guidelines and methodologies 
for estimating the impact of 
changes in the climate on the 
electricity system. Implement 
and periodically review 
adaptation plans.

Government

Continue to work with the 
global community, through 
international agreements 
for greenhouse gas emission 
reduction, to reduce the risk of 
climate change impacts.







ISSUE

CHALLENGES

RISKS AND BARRIERS

OPTIONS FOR MANAGING 
THE CURRENT TRANSITION

Increasing 
natural gas 
prices

Wholesale electricity 
prices are projected to be 
$11/MWh (1.1 c/kWh) higher 
and greenhouse gas emissions 
34 per cent higher by 2050 
relative to Scenario 1 if there 
is a higher rate of growth in 
gas prices.

Under the BREE (2012) cost 
assumptions, gas combined 
cycle (that is, baseload) plants 
are one of the lowest-cost 
forms of electricity 
generation. Further, gas 
peaking plants may play an 
important role in supporting 
variable renewables.

Government

Although markets and costs 
of production will determine 
prices, governments can 
continue to support efficient 
and transparent markets for 
gas exploration, production, 
generation, trade and 
consumption.

Expand the Australian Energy 
Technology Assessment 
process to include large-scale 
storage technologies, which 
are a potential substitute for 
gas in supporting variable 
renewable generation.

The role of 
nuclear power

Wholesale electricity 
prices are projected to be 
$34/MWh (4 c/kWh) lower 
and greenhouse gas emissions 
72 per cent lower by 2050 
relative to Scenario 1 if nuclear 
power is included in the 
electricity generation mix.

The BREE (2012) cost 
assumptions, on which this 
projection is based, do not 
include decommissioning.

There would be considerable 
delay (assumed to be after 
2025 in this study) before 
nuclear plant could contribute 
to electricity generation in 
Australia because of long 
construction times, skill 
shortages, and necessary 
development of regulations 
and policy changes.

Non-cost factors are 
important in technology 
adoption. Nuclear power 
consistently rates at the 
lower end of the scale of 
social acceptance relative to 
other electricity generation 
technologies (for example, 
Ashworth et al 2012).

Industry and government

Continue to monitor 
and evaluate the social 
acceptability of nuclear power 
and other barriers to its uptake 
not explored in this report.





Many of the options in Table 4 are not new, but rather 
support existing processes or market arrangements. 
For example, the Forum considers that the existing 
market arrangements in the National Electricity 
Market and the existing market information 
provision functions of the Australian Energy Market 
Operator are already providing clear signals to 
market participants. This report highlights the need 
to accelerate the evaluation and, if appropriate, the 
implementation of existing recommendations to 
support peak demand reduction, but recognises that 
electricity market reform in Australia is necessarily 
time-consuming because of the multiple jurisdictions 
involved in decision-making and the need for robust 
information and consultation processes. The Forum 
believes that mechanisms to accelerate these 
processes should be investigated given that electricity 
markets have shown the tendency to undergo 
major and rapid shifts that are able to outpace the 
reform processes’ ability to implement change. 



Rapid uptake of roof-top solar photovoltaics has 
occurred in two years, which is approximately the 
timeframe for minor rule changes. (More than five 
years is generally required for major structural reform, 
such as the establishment of the National Electricity 
Market, and fixed five-year regulatory reset cycles are 
used for new rules relating to network expenditure.) 

In 2012, the Australian Government commenced an 
Australian Energy Technology Assessment focusing on 
centralised electricity generation technologies. In light 
of the Future Grid Forum scenarios, expanding the 
scope of the AETA to include on-site generation and 
storage technologies would be appropriate given their 
potential to shape the future of the electricity system.

Of the options presented in Table 4, there 
are four that are not already established but 
could be considered as potential approaches 
to addressing the issues identified in the 
scenarios. These four are expanded here: 

1. Implement a sustained long-term program 
to increase consumer awareness of the 
benefits and mechanisms of cost-reflective 
pricing and demand management.


As part of addressing a potential decline in 
network utilisation through various reform 
measures, readying consumers for cost-reflective 
pricing might require more than deregulation. 
Information campaigns over several years, perhaps 
similar in scale to those implemented to increase 
awareness of energy-efficiency measures for 
households and businesses, might be warranted.

Cost-reflective pricing (that is, pricing that accurately 
reflects the cost of delivering a particular service that 
could include more than just electricity) empowers 
consumers to make informed decisions that lead 
to more optimal long-term outcomes because 
the system provides the services that consumers 
are willing to pay for at the price they cost. But as 
the Forum’s social research indicates, consumer 
knowledge is low, particularly about which appliances 
most affect their electricity use. Consumers can also 
be cynical about new technologies, such as smart 
meters, particularly if the technology is mandated 
rather than actively chosen. Change could be 
politically challenging, but for consumers to access 
many of the benefits of demand response, on-site 
generation, and energy efficiency that were included 
in the Forum’s scenarios, a change to cost-reflective 
pricing and an ability to adopt and respond to those 
price signals is a prerequisite. The Power of choice 
(AEMC 2012a) review makes recommendations for 
implementing cost-reflective pricing, and New 
South Wales and Queensland are considering price 
deregulation, which will enable it in those states 
(following the lead of South Australia and Victoria).

2. Develop bipartisan agreement on the long-
term (2050) greenhouse gas emission target 
and implementation mechanism for Australia.


Australia’s carbon policy continues to substantially 
change during and following each change of 
government or political leader. Failure to reach a 
bipartisan position on the implementation mechanism 
and emission target beyond 2020 is preventing the 
electricity sector from responding in the most efficient 
way possible and outcomes will only get worse the 
longer uncertainty continues. No industry can or 
should expect policy to remain constant throughout 
the life of its investments, but given that the electricity 
supply chain involves very long-lived investments in 
what can be described as one of the most complex 
systems on the planet, a non-political approach 
leading to some form of predictability is warranted.

Specifically, the electricity sector and its customers 
would benefit from bipartisan support for a long-term 
abatement target and implementation mechanisms 
to 2050, including interim targets for each decade. 
While the sector would expect some changes 
over time, a credible long-term abatement target 
and implementation mechanisms would provide 
much-needed guidance on the emissions outcomes 
expected of the next fleet of electricity plants. The 
implementation mechanisms should heed other 
electricity system performance indicators, such as 
minimising whole-of system cost and maximising 
reliability and resilience through flexibility, but 
there will be a need to trade off some of these 
objectives against each another and against the 
needs of other sectors subject to the carbon policy.

These conclusions about carbon policy would likely 
also apply to renewable energy targets and policies, 
although the Forum did not specifically model 
the impact of uncertainty on renewable policy.



3. Review Australia’s electricity 
consumer social safety net.


Unfortunately, the Forum’s scenarios have not been 
able to rule out further electricity bill increases, 
but the Forum does expect more options for 
managing consumers’ exposure to cost increases 
to become available to consumers. Examples are 
further energy-efficiency opportunities, greater 
potential for use of on-site generation, and 
implementation of cost-reflective pricing to reduce 
cross-subsidisation of heavy system users and to 
support efficient investments throughout the system.

To provide further support to this option, 
governments could consider:

..developing a national consumer protection 
framework for deregulated markets that 
considers the need for any protections for 
new tariff types and other demand-side 
participation options, including guidelines on 
consumer rights in phasing out older tariffs
..developing a nationally consistent framework for 
energy concessions and emergency assistance 
that ensures the most vulnerable consumers can 
afford to remain connected to electricity supplies
..regularly reviewing the impact of carbon 
pricing relative to the tax offsets provided 
to low-income wage earners
..more targeted, flexible and innovative packages of 
social safety net measures, including, for example, 
energy-efficiency standards for rental properties and 
incentives for landlords to invest in energy efficiency 
and on-site generation; energy-efficiency retrofits 
and on-site generation for social housing stock; 
low-interest microfinance schemes for improving 
low-income households’ electricity cost resilience; 
direct engagement to address information barriers 
to energy efficiency and new tariff options.


A major challenge in addressing this issue is for 
governments to find the balance between meeting 
community expectations of protection for the most 
vulnerable consumers and not stifling innovation in 
deregulated electricity retail markets. Governments 
will need to consult with industry to determine 
whether the market can develop satisfactory 
solutions, particularly to issues such as financing.

4. Establish processes to identify the 
changes, if any, that might be required 
to market frameworks in light of the 
megashifts examined in this report. 


The Future Grid Forum has developed scenarios 
to 2050 focusing on the potential megashifts of 
low-cost electricity storage, sustained low demand 
for centrally-supplied electricity, and the need for 
significant greenhouse gas abatement. The scenarios 
highlight the potential, in some cases, for dramatic 
changes in the way electricity is transacted, and in 
the roles of various parties, particularly customers. 

The Forum process has delivered scenarios that 
provide a ’technical’ view of potential futures and 
provide some insight into the changes that may occur 
in each of the industry sectors, but other processes 
may need to be established to consider whether the 
current market and regulatory frameworks will be 
consistent with these futures, and whether or not 
there are some changes that need to be considered to 
facilitate the transition to the future arrangements.

Given the nature of the megashifts identified, 
it would not be surprising if some changes 
were required and it would be sensible to start 
considering these now, at least at a high level. 
There may be some common issues where it is 
worth developing an early understanding of the 
feasibility of the alternative options available.



References























ACIL Tasman 2012, Fuel cost projections: updated 
natural gas and coal outlook for AEMO modelling, 
Report prepared for Australian Energy Market 
Operator, ACIL Tasman, Melbourne, <

http://www.
aemo.com.au/~/media/Files/Other/planning/ACIL_
Tasman_Fuel_Cost_%20Projections_2012.ashx>.

Ashworth, P, Hobman, L & Shaw, H 2012, ‘The 
Australian public’s preference for energy sources 
and related technologies’, CSIRO, Clayton, 
Victoria, <

https://publications.csiro.au/rpr/download?pid=csiro:EP123524&dsid=DS1>.

Australian Bureau of Statistics 2013a, 6401.0 
Consumer Price Index, Australia, Table 7. CPI: 
group, sub-group and expenditure class, weighted 
average of eight capital cities, ABS, Canberra.

—— 2013b, Energy account, Australia, 2010-11, ABS, 
Canberra.
—— 2011, Environmental issues: energy use and 
conservation, March 2011, ABS, Canberra.

Australian Communications and Media Authority 
2011, Reconnecting the customer: final public inquiry 
report, ACMA, Canberra, <

http://www.acma.gov.au/
webwr/_assets/main/lib310013/rtc_final_report.pdf>.

Australian Energy Market Commission 2012a, 
Final report: power of choice review – giving 
consumers options in the way they use electricity, 
AEMC, Sydney South, <

http://www.aemc.
gov.au/media/docs/Final-report-1b158644-
c634-48bf-bb3a-e3f204beda30-0.pdf>.

—— 2012b, Final report – NSW Workstream: review 
of distribution reliability outcomes and standards, 
AEMC, Sydney South, <

http://www.aemc.gov.
au/Media/docs/NSW-workstream-final-report-
160466c4-733b-4cf2-b4e3-4095c6d9819b-0.pdf>.

—— 2013a, Electricity price trends final report. 
Possible future retail electricity price movements: 
1 July 2012 to 30 June 2015, AEMC, Sydney.

—— 2013b, Consultation paper: review of the national 
frameworks for transmission and distribution reliability, 
AEMC, Sydney South, <

http://www.aemc.gov.au/
Market-Reviews/Open/review-of-the-national-
framework-for-distribution-reliability.html>.

—— 2013c, Final report: review of the national 
frameworks for transmission and distribution reliability, 
AEMC, Sydney South, <

http://www.aemc.gov.au/
Market-Reviews/Open/review-of-the-national-
framework-for-distribution-reliability.html>.

Australian Energy Market Operator 2013a, 100 
percent renewable study modelling outcomes, AEMO, 
Sydney, <

http://www.climatechange.gov.au/sites/
climatechange/files/documents/08_2013/100-percent-
renewables-study-modelling-outcomes-report.pdf>.

—— 2013b, Final NEM and regional forecasts, 
AEMO, Sydney, <

http://www.aemo.com.au/
Electricity/Planning/Forecasting/National-
Electricity-Forecasting-Report-2013>.

—— 2013c, 2013 forecasting methodology 
information paper: national electricity forecasting, 
AEMO, Sydney, <

http://www.aemo.com.au/
Electricity/Planning/Forecasting/National-
Electricity-Forecasting-Report-2013/~/media/
Files/Other/planning/NEFR/2013/Forecast%20Methodology%20Information%20Paper.pdf.ashx>.

Boughen, N, Contreras Castro, Z & Ashworth, 
P 2013, Understanding the residential consumer 
viewpoint to emerging electricity technologies, 
CSIRO, Clayton South, Victoria.

Bureau of Resources and Energy Economics 
2012, Australian Energy Technology Assessment, 
BREE, Canberra, <

http://www.bree.gov.au/
documents/publications/aeta/australian_
energy_technology_assessment.pdf>.

Climate Change Authority 2013, Caps and 
targets review: issues paper, CCA, Canberra.



Commonwealth Scientific and Industrial Research 
Organisation 2009, Intelligent grid: a value proposition 
for distributed energy in Australia, CSIRO, Clayton 
South, Victoria, <http://www.csiro.au/en/Outcomes/
Energy/Carbon-Footprint/IG-report.aspx>. 

Department of Industry, Innovation, Climate Change, 
Science, Research and Tertiary Education 2013, 
Australian National Greenhouse Accounts: quarterly 
update of Australia’s national greenhouse gas inventory, 
December quarter 2012, DIICCSRTE, Canberra.

ClimateWorks 2013, Tracking progress towards a low 
carbon economy, ClimateWorks, Melbourne, <http://
www.climateworksaustralia.org/project/current/
tracking-progress-towards-low-carbon-economy>.

Department of the Environment, Water, 
Heritage and the Arts 2008, Energy use in 
the Australian residential sector 1986–2020, 
Commonwealth of Australia, Canberra.

Energy Supply Association of Australia n.d., 
Electricity Australia, various issues, (superseded 
by Electricity Gas Australia), ESAA, Melbourne.

Graham, P, Brinsmead, T & Marendy, P 2013a, 
efuture sensitivity analysis 2013, CSIRO, Clayton 
South, Victoria, <http://www.efuture.csiro.au/docs/
efuture_summary_report_26-06-2013.pdf>.

——, ——, Dunstall, S, Ward, J, Reedman, L, 
Elgindy, T, Gilmore, J, Cutler, N & James, G 
2013b, Modelling the Future Grid Forum 
scenarios, CSIRO, Clayton South, Victoria.

Hayward, J & Graham, P 2012, AEMO 100 per cent 
renewable energy study: projection of electricity 
generation technology capital costs for Scenario 1, 
CSIRO, Clayton South, Victoria, <http://www.
climatechange.gov.au/sites/climatechange/
files/files/reducing-carbon/APPENDIX10-CSIRO-
GALLM-gen-tech-capital-costs-scenario.pdf>.

Independent Pricing and Regulatory Tribunal 
2013, Review of regulated retail prices and charges 
for electricity from 1 July 2013 to 30 June 2016. 
Electricity – final report, IPART, Sydney.

International Energy Agency 2012, Energy 
technology perspectives 2012, IEA/OECD, Paris.

James, G & Hayward, J 2012, AEMO 100 
per cent renewable energy study: energy 
storage, CSIRO, Clayton South, Victoria.

Marchment Hill Consulting 2012, Energy 
storage in Australia: commercial opportunities, 
barriers and policy options, Report for the 
Clean Energy Council, MHC, Melbourne.

Nelson, T, Kelley, S, Orton, F & Simshauser, P 
2011, ‘Delayed carbon policy certainty and 
electricity prices in Australia’, Economic 
Papers, vol. 29, no. 4, pp. 446–465.

Rushe, D 2013, ‘BlackBerry goes up for sale 
after years of struggle in smartphone market’, 
The Guardian, 13 August 2013, <http://www.
theguardian.com/technology/2013/aug/12/
blackberry-for-sale-smartphone-market>.

Treasury 2011, Strong growth, low pollution: 
modelling a carbon price, Treasury, Canberra, 
<http://carbonpricemodelling.treasury.gov.au/
carbonpricemodelling/content/default.asp>.

Wood, T 2012, Putting the customer back in 
front: how to make electricity cheaper, Grattan 
Institute, Carlton, Victoria, <http://grattan.edu.
au/static/files/assets/7a8390e0/178_energy_
putting_the_customer_back_in_front.pdf>.

—— & Carter, L 2013, Getting gas right: Australia’s 
energy challenge, Grattan Institute, Carlton, 
Victoria, <http://grattan.edu.au/static/files/assets/
ba24a4e0/189_getting_gas_right_report.pdf>.



Glossary 

ITEM

DEFINITION

$/MWh

dollars per megawatt hour

c/kWh

cents per kilowatt hour

consumption

the total volume of electricity consumed over a given period measured in watt-hours

cost

the expenditure required to deliver a service (in contrast to ‘price’)

kW

kilo (a thousand) watts

MW

million watts

on-site generation

generation that occurs at the site of the electricity consumption as opposed 
to remotely and supplied through the transmission and distribution network. 
Also known as distributed generation or embedded generation

peak demand

the highest instantaneous level of demand experienced in a given period, 
measured in watts

ppm

parts per million

price

the fee charged for a service (in contrast to ‘cost’)

MtCO2e

million tonnes of carbon dioxide equivalent

NEM

the National Electricity Market comprising the southern and eastern states of 
Australia and excluding Western Australia and the Northern Territory

RET

Renewable Energy Target

TWh

a thousand billion watt hours







CONTACT US

t 1300 363 400 
+61 3 9545 2176
e enquiries@csiro.au
w www.csiro.au

YOUR CSIRO

Australia is founding its future on 
science and innovation. Its national 
science agency, CSIRO, is a powerhouse 
of ideas, technologies and skills for 
building prosperity, growth, health and 
sustainability. It serves governments, 
industries, business and communities 
across the nation.


FOR FURTHER INFORMATION

CSIRO Energy Flagship

Paul Graham
t +61 2 4960 6061
e paul.graham@csiro.au
w www.csiro.au/energy