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Appendix D Progress towards Australia’s emissions reduction targets

In considering Australia’s emissions reduction goals, it is important to understand the outlook for domestic emissions and how different sectors of the economy might contribute to meeting those goals.

As outlined in Chapter 1, the Clean Energy Act 2011 (Cth) requires the Authority to review Australia’s progress towards its medium and long term emissions reduction goals each year. This review of progress is due in February 2014. Appendix D, together with chapters 7, 12 and 13, relates to the Authority’s legislative requirements regarding the review of progress. Appendix D1 sets out the purpose, scope and approach to the review of progress. Appendix D2 highlights the outlook for emissions from the Australian economy as a whole. Appendices D3 to D10 outline the outlook for changes in emissions from each sector, expanding on the discussion in Chapter 12.

The Authority has based its review of progress on the four scenarios described in Chapter 10 and Appendix C (no price, low, medium and high scenarios). The Authority has also drawn on additional published material and expert input to provide a broader review of possible future outcomes.

Without additional incentives to reduce emissions, emissions from most sectors of the Australian economy are projected to rise due to strong population and economic growth.

Australia has significant emissions reduction opportunities in the domestic economy. A price incentive could drive substantial emissions reductions, particularly in electricity generation, industrial processes and fugitive emissions. Stronger incentives would drive deeper emissions reductions. The minimum 5 per cent emissions reduction target could be achieved through domestic emissions reductions alone, provided appropriate incentives applied. Stronger targets could be met using a mixture of domestic and international emissions reductions, or using higher price incentives or other policies.

The most important sector for potential emissions reductions is electricity. It has the largest share of Australia’s emissions and emissions from electricity are projected to grow strongly without price incentives or additional policies. The electricity sector, however, is also projected to account for the largest share of emissions reductions in scenarios with a price incentive analysed by the Authority.

Even with a strong incentive to reduce emissions, growth in export-oriented activity, such as liquefied natural gas production and agriculture, is projected to increase absolute emissions in those sectors despite emissions intensity improvements.

In addition to the opportunities identified in The Treasury and DIICCSRTE modelling (2013), further emissions reductions in the economy may be delivered by removing non-price barriers to energy efficiency and promoting the uptake of more efficient vehicles in the transport sector. The Authority supports considering how these opportunities could be cost-effectively pursued in the new policy environment, including the most sensible mix of responsibilities across state and Commonwealth jurisdictions.

Appendix D1 Evaluating progress

D1.1 Purpose and scope of the review of progress

This Appendix, combined with Chapter 7 and Part D of the Targets and Progress Review, relates to the Authority’s legislative requirements for reporting on progress towards Australia’s future emissions reduction goals.

To meet its emissions reduction goals, Australia has implemented a range of legislative and policy measures. This review of progress assesses how Australia is tracking towards its emissions reduction goals, providing important feedback to governments on changes taking place in the economy in response to these policy measures and other factors.

This review of progress focuses on the outlook for emissions across the economy under several scenarios and also considers the outlook for changes in emissions in different sectors. The approach is designed to assess not only if Australia’s emissions targets will be met but also how Australia will achieve its emissions reduction targets.

Australia has emissions reduction goals for its economy overall, rather than sector-specific targets. Notwithstanding this, considering the projected outcomes in each sector is useful in identifying opportunities to transition to a lower emissions economy, and determining the efficiency of policy measures and their impact on different sectors.

D1.2 Stakeholder views on the Authority’s review of progress

Some stakeholder submissions to the Issues Paper for this Review raised concerns that assessing progress by reference to developments in each sector may imply sector-specific emissions targets or development pathways. There were concerns such an approach could compromise Australia’s broad-based approach to reducing emissions.

The Authority does not intend for the review of progress to recommend binding sector-specific objectives or to prescribe pathways, technologies or activities to reach Australia’s emissions reduction goals. Rather, the review of progress synthesises information from multiple sources to better understand possible paths towards emissions reduction and the factors (‘contributors’) likely to lead to significant changes in emissions. The Authority’s analysis considers the likelihood and timing of potential outcomes. This can help identify if Australia is on track to meet its broader national emissions reduction goals, and how those goals may be met.

Some stakeholders called for a focus on policy as a driver of changes in emissions. The Authority is not seeking to estimate the change in emissions expected to result from particular policy or legislation through the review of progress. This is generally done as part of the process of developing or evaluating specific regulatory instruments. The review will instead, to the extent possible, seek to identify drivers of change in emissions; across successive annual progress reviews this could enable the identification of policies with a significant effect on activity and emissions.

The review does not explicitly assess the cost-effectiveness of policies but it does note opportunities for changes in technology or behaviour to increase the uptake of cost-effective emissions reductions in future, and notes policy options and examples which warrant further investigation. The Authority aims to focus on the most substantive contributors and drivers of emissions outcomes. While policy is relevant, macroeconomic and other drivers are also important.

D1.3 Framework for analysing progress in this review

The Authority’s analytic framework for assessing progress considers:

  • Australia’s domestic emissions levels, recent trends and projections; and
  • historical and projected sectoral emissions outcomes, the key contributing factors to delivering those outcomes, and the underlying economic, policy and technological drivers.

The economy-wide analysis in Appendix D2 describes the broad trends in Australia’s historic emissions levels, projected emissions levels and emissions intensity of the economy. In subsequent progress reviews, the economy-wide analysis could outline how Australia is tracking against its emissions targets and budget for the periods 2013 to 2020 and to 2050. The distinction between emissions and emissions intensity is useful, given the projected continued strong growth in activity for most parts of the economy. It is also useful in informing policy, since different policy instruments often focus on either decreasing emissions intensity, or changing demand or activity.

The economy-wide analysis considers the relative contribution of different sectors to changes in domestic emissions, based on taking up emissions reduction opportunities to a certain marginal cost.

The sectoral analysis of progress (appendices D3 to D10) identifies potential emissions outcomes in absolute terms, and in terms of activity levels and emissions intensity where practical and beneficial. The sectoral analysis explores the effect of a range of contributors and underlying drivers on these emissions. Sectoral analyses are designed to, over time:

  • identify the greatest contributors to changes in sector emissions, including those that affect levels of activity and the emissions intensity of the sector’s activity;
  • track the main contributors to projected emissions outcomes and the drivers that underpin them; and
  • allow comparison between modelled and realised sectoral outcomes, helping to anticipate when contributors or drivers will persist, subside or recur.

D1.4 Assessing emissions changes against a fixed baseline

This Appendix does not focus on emissions reduction relative to a concept of business as usual (or ‘no price’ scenario). Business as usual (BAU) projections depend on the broader economic and policy context at a point in time and, as such fail to provide a stable and robust basis for tracking progress towards fixed, long term targets. Instead, the Authority uses 2000 as the base year against which to assess changes in emissions. This approach:

  • is consistent with the expression of Australia’s emission reduction targets;
  • avoids the use of a BAU reference, supporting longer term comparison of Australia’s progress that remains relevant as the economic conditions and legislative framework change over time; and
  • is easily rebased to alternative reference years, if required.

Australia’s total emissions in 2000 were 586 million tonnes of carbon dioxide equivalent (Mt CO2-e).

D1.5 Synthesising data sources and quantifying emissions

This review of progress uses historical and projected emissions for the period 1990 to 2030 from The Treasury and DIICCSRTE modelling (2013). In that report:

  • the data incorporates updated National Greenhouse Gas Inventory data for the 2010–11 inventory year and preliminary emissions estimates for 2011–12 and 2012–13;
  • the data includes updates to the global warming potentials published in the Intergovernmental Panel on Climate Change (IPCC) Second Assessment Report (AR2) to those in its Fourth Assessment Report (AR4);
  • for 2012, historical emissions are based on yet-to-be published March 2013 quarterly inventory data, with the exception of waste emissions, which are modelled estimates;
  • historical emissions for the land use, land use change and forestry sector (LULUCF) for the period 1990 to 2012 are based on an estimate of emissions consistent with the new accounting rules (Article 3.4) agreed for the second commitment period of the Kyoto Protocol; and
  • data for emissions for the period 2013 to 2030 are modelled estimates (see Appendix C).

All data in this report is for the financial year ending 30 June unless otherwise indicated. For example, data reported for 2013 is for the financial year 2012–13. All dollar amounts (prices and costs) reported in this Appendix are 2012 Australian dollars, unless otherwise stated.

Modelling from The Treasury and DIICCSRTE has formed the core data set analysed in this review of progress. The electricity, transport and agriculture sectors have been modelled separately in greater detail, and scenarios and sensitivities from these models are also included.

The Treasury and DIICCSRTE modelling examines four core scenarios – one without a carbon price, and three different price levels. The four scenarios are:

  • No price scenario – assumes there is no carbon price and no Carbon Farming Initiative. This scenario includes emissions reductions from pre-existing measures such as energy efficiency measures and the Renewable Energy Target (RET).
  • Low scenario – additionally assumes the carbon price and Carbon Farming Initiative are in place. The carbon price is fixed for two years, then moves to a flexible price. The flexible price begins at $5.49/tonne of carbon dioxide equivalent (t CO2-e) in 2015, and grows at 4 per cent per year in real terms to reach $6.31 in 2020. The price then follows a linear transition to $54.48 in 2030.
  • Medium scenario – assumes the fixed price for two years, then a flexible price beginning at $5.49/t CO2-e in 2015, and following a linear transition to $30.14 in 2020. From 2021 onward, the price follows the international price from the medium global action scenario, which grows at 4 per cent per year in real terms in US dollars.
  • High scenario – assumes the fixed price for two years, then a flexible price beginning at $5.49/t CO2-e in 2015, and following a linear transition to $73.44 in 2020. From 2021 onward, the price follows the international price from the ambitious global action scenario, which grows at 4 per cent per year in real terms in US dollars.

Chapter 10 of this review and Table 3.1 of The Treasury and DIICCSRTE (2013) modelling report provide further details of the scenario assumptions.

Considering uncertainty is fundamental to assessing future outcomes. Australia’s emissions may be higher or lower as a result of changes in the level of global action on climate change, the Australian legislative framework, economic growth, demographic factors and technology costs, among other things. The review of progress notes opportunities, risks and barriers to delivering emissions reductions projected in recent modelling and analysis. The Authority considers the four scenarios described earlier, alongside sensitivity analyses and alternative projections, to explore some important variables.

The Authority acknowledges that modelling presents possible future outcomes based on a particular set of assumptions. Therefore, the Authority’s analysis has drawn on additional published sources and expert inputs to supplement modelling results to give a broader picture of potential futures. This Appendix explores opportunities for greater emissions reductions than those projected, and also risks and barriers to realising the emissions outcomes projected by the modelling.

This review of progress provides a more detailed assessment of the outlook for the electricity sector than for other parts of the economy. In subsequent progress reviews, similarly detailed consideration of emissions from other sectors could be undertaken, over time building an economy-wide picture of possible paths for changes in emissions.

D1.6 Considering activity and supply intensity

In this review of progress, emissions are disaggregated into activity levels and emissions intensity to give a more comprehensive picture of Australia’s progress. For example, emissions in the electricity sector are affected by both the amount of electricity generated (the activity level) and the emissions intensity of the electricity supply. The Authority considers it important to highlight the extent to which emissions levels, both historical and projected, reflect changing levels of activity compared with the emissions intensity of that activity.

D1.7 Reviewing progress in the domestic economy by sector

The Authority has adopted the same approach to defining sectors as is used in Australia’s National Greenhouse Gas Inventory to organise its sector-level reporting and analysis: electricity generation; transport; direct combustion; fugitives; industrial processes; agriculture; land use, land use change and forestry; and waste.

The Authority also uses complementary analysis of end-use emissions where it provides additional information, or is particularly relevant to considering opportunities for, or barriers to, cost-effective emissions reduction.

D1.8 Selecting contributors and drivers

The Authority analyses progress in terms of contributors and drivers.

D1.8.1 Contributors

In reviewing progress, the Authority considers which factors are expected to contribute significantly to emissions outcomes. Contributors are changes that directly affect the emissions outcomes. They may include factors that affect emissions intensity, such as changes in process, fuels or technology. The level of activity in a sector will generally be a contributor to the emissions outcomes.

The Authority has focused on contributors to emissions outcomes that are:

  • projected to deliver a significant proportion of Australia’s changes in emissions by 2050, whether at a point in time or in aggregate (nominally over 5 per cent of domestic emissions changes); or
  • among the top few contributors to emissions reductions, at a point in time or in aggregate, in a sector.

The Authority has also examined other contributors that:

  • could be deployed broadly across the sector under plausible conditions;
  • are likely to lock in emissions reductions (or increases);
  • have a relatively long lead time for deployment;
  • offer low-cost emissions reductions;
  • offer significant cobenefits (or disbenefits) outside of their potential emissions impacts; or
  • are explicitly identified by sector experts for other reasons.

D1.8.2 Drivers

Drivers are the underlying factors that promote or impede contributors, but do not directly affect emissions outcomes. Drivers may include factors such the rate of growth in Gross National Income (GNI), relative technology costs, population growth or policy.

The underlying drivers are identified to give a sense of the risks, uncertainties, barriers and opportunities to domestic emissions reduction and, therefore, Australia’s progress to its emissions reduction goals.

D1.8.3 Illustrating progress

The review of progress introduces two styles of charts to assist in describing Australia’s progress towards its emission reduction goals.

Australia’s emissions are, generally, characterised by decreases in emissions intensity offsetting increasing activity. This review of progress introduces charts showing changes in emissions intensity against demand side activity (Figure D.1). Expression of emissions in this form highlights whether increasing activity or decreasing supply intensity have the greatest effect on absolute emissions.

The horizontal axis represents total activity levels in the relevant sector. Depending on the sector, activity may be, for example, electricity generated, energy combusted or kilometres travelled. The vertical axis represents the emissions per unit of activity. It is a measure of emissions intensity in the relevant sector. Curved isolines represent absolute emissions levels. The plot(s) on the chart are presented to show the historical and projected changes in activity, emissions intensity and absolute emissions. Date labels indicate the progression of emissions outcomes over time.

Figure D.1: Examples of trends in emissions intensity and activity

Figure D.1 is an example of figures showing trends in emissions intensity and activity. The horizontal axis represents total activity levels in the relevant sector. Depending on the sector, activity may be, for example, electricity generated, energy combusted or kilometres travelled. The vertical axis represents the emissions per unit of activity. It is a measure of emissions intensity in the relevant sector. The plot(s) on the chart are presented to show the historical and projected changes in activity, emissions intensity and absolute emissions. Date labels indicate the progression of emissions outcomes over time. 

Figure D.1 shows four plot examples:

  • Plot A shows a trend of increasing emissions intensity and activity, with corresponding increasing absolute emissions levels;
  • Plot B shows a trend of stable emissions intensity coupled with activity growth, leading to increasing levels of absolute emissions;
  • Plot C shows a trend of falling emissions intensity balancing increasing activity levels, leading to stable absolute emissions (following the emissions isoline); and
  • Plot D shows a trend of falling emissions intensity against stable activity levels, leading to a reduction in absolute emissions.

The review of progress also uses charts to summarise projected emissions outcomes for a given year, as well as the contributors to changes in emissions outcomes, relative to 2000 emissions levels (Figure D.2).

Read from left to right, the bars represent the increasing level of price incentive, from the ‘no price’ scenario to the ‘high’ scenario, for a given sector.

Each bar is divided into the main contributors to changes in emissions, whether increasing or decreasing emissions, compared to 2000 levels. These contributors may represent changes in activity levels, supply intensity, or the net contribution of a particular subsector or other area of interest.

The net change in emissions – that is, the sum of all the contributors – is represented by the orange circles.

Figure D.2: Examples of trends in emissions intensity and activity, 1990–2030

Figure D.2 is an example of figures showing trends in emissions intensity and activity. Read from left to right, the bars represent the increasing level of price incentive, from the ‘no price’ scenario to the ‘high’ scenario, for a given sector. Each bar is divided into the main contributors to changes in emissions, whether increasing or decreasing emissions, compared to 2000 levels. These contributors may represent changes in activity levels, supply intensity, or the net contribution of a particular subsector or other area of interest.

Appendix D2 whole-of-economy

D2.1 Indicators for the Australian economy

As described in Chapter 7, Australia’s domestic emissions have grown by a small amount since 2000, despite significant population and economic growth.

Since 2000, Australia’s emissions have increased by 2.5 per cent, driven by increases in emissions across most sectors. Emissions from LULUCF have offset much of the increase from the remainder of the economy.

The Treasury and DIICCSRTE modelling projects that between 2000 and 2020 emissions could rise by 17 per cent in the no price scenario and fall by 6 per cent under the high scenario. The modelling also projects that between 2000 and 2030 emissions could rise by 37 per cent in the no price scenario and fall by 21 per cent under the high scenario (see Figure D.3). The modelling indicates that the electricity generation sector will account for the largest emissions reduction of any sector in the low, medium and high scenarios, followed by fugitive emissions reduction.

Emissions intensity of the economy, as indicated by the ratio of domestic emissions to gross domestic product (GDP), has reduced 28 per cent since 2000 and is projected by The Treasury and DIICCSRTE, under all scenarios, to decline to 2030 (figures D.4 and D.5)

Figure D.3: Australia’s emissions, 1990–2030

Source: Climate Change Authority calculations using results from The Treasury and DIICCSRTE 2013

Figure D.4: Australia’s GDP per person, emissions per person and emissions intensity, 2000–2030

Figure D.4 shows Australia’s historical and projected GDP per person, emissions per person and emissions intensity between 2000 and 2030, as a percentage of 2000 levels in the no price and high scenarios. Australia’s emissions per person and emissions intensity were 86 and 72 per cent of 2000 levels between 2000 and 2012 respectively, while GDP rose to 119 per cent of 2000 levels over the same period. Projected GDP per capita is 154 and 150 per cent of 2000 emissions in 2030 in the no price and high scenarios, respectively. Emissions per capita is projected to be 86 and 50 per cent of 2000 emissions in 2030 in the no price and high scenarios, respectively. Australia’s GDP per person is projected to be 56 and 33 per cent of 2000 emissions in the 2030 in the no price and high scenarios, respectively.

Source: Climate Change Authority calculations using results from The Treasury and DIICCSRTE 2013

Similarly, the level of emissions per person has fallen by almost 15 per cent since 2000 and is projected by The Treasury and DIICCSRTE to continue to decline in the low, medium and high scenarios (or, in the ‘no price’ scenario, to remain relatively stable) as depicted in figures D.4 and D.6). In contrast, as shown in Figure D.4, GDP per person has grown since 2000 and is projected to continue to grow in all scenarios.

From 2012 to 2030, The Treasury and DIICCSRTE’s modelling projects that the economy will grow by between about 65 per cent under a high scenario and 70 per cent under a no price scenario. Population is projected to increase by almost one-third. Over the same period, Australia’s domestic emissions, under a no price scenario, are estimated to rise by as much as 33 per cent relative to 2012 levels. Australia’s emissions under a high scenario, however, are estimated to fall by about 23 per cent from 2012 to 2030, leading to substantial declines in Australia’s emissions intensity.

Despite the reduction in Australia’s emissions intensity to date, the no price scenario suggests that Australia’s emissions will rise to about 17 per cent above 2000 levels by 2020 and 37 per cent above 2000 levels by 2030, as shown in Figure D.3. The high scenario gets closest to cumulative emissions reductions consistent with Australia’s minimum 5 per cent emissions reduction commitment. Under the no price, low and medium scenarios, it is projected that domestic emissions reductions will be insufficient for Australia to meet its 2020 target.

Figure D.5: Australia’s emissions intensity – emissions per unit GDP ($2012), 2000–2030

Figure D.5 shows Australia’s historical and projected emissions intensity per unit of GDP between 2000 and 2030 in each scenario. Australia’s emissions intensity per unit of GDP fell between 2000 and 2012 and is predicted to continue falling across all scenarios to 2030.

Source: Climate Change Authority calculations using results from The Treasury and DIICCSRTE 2013

Figure D.6: Australia’s emissions intensity – emissions and population, 2000–2030

Figure D.6 shows Australia’s historical and projected emissions intensity per person between 2000 and 2030 in each scenario. Australia’s emissions intensity per person fell between 2000 and 2012 and is projected to continue to decline to 2030 in all scenarios, except the no price scenario (which is projected to remain relatively steady).

Source: Climate Change Authority calculations using results from The Treasury and DIICCSRTE 2013

D2.2 Overview of sectoral progress

Electricity generation and direct combustion emissions are projected to continue to account for about half of Australia’s total emissions over the period to 2030. Transport, fugitive and agricultural emissions are forecast to make up the majority of the remaining emissions.

Growth in direct combustion, fugitive and agricultural emissions is projected to offset reductions in waste, industrial process and electricity emissions over the period to 2030 in the low, medium and high scenarios.

Figure D.7 shows that an emissions reduction of around 134 Mt CO2-e could be achieved in 2020 under the high scenario compared to the no price scenario, which is broadly consistent with the minimum reduction required to deliver the minus 5 per cent target.

ClimateWorks Australia, in its 2013 Tracking Progress report, provides another insight. ClimateWorks found that if current emissions reduction trends continue, by 2020 Australian domestic emissions could be 40 per cent of the way to delivering the reduction needed to meet a 5 per cent emissions reduction target in 2020.

Figure D.7: Changes in Australia’s emissions – no price and high scenarios, 2012–2030

Figure D.7 shows changes in Australia’s projected emissions by sector in the no price and high scenarios between 2012 and 2030. Emissions in the high scenario are projected to decrease by 49 megatonnes of carbon dioxide equivalent between 2012 and 2020, with the largest decrease in emissions coming from electricity generation and the largest increase from direct combustion emissions. In the no price scenario, emissions are projected to increase by 84 megatonnes of carbon dioxide equivalent between 2012 and 2020, with emissions increasing in all sectors, particularly direct combustion and fugitive emissions. In the high scenario emissions are projected to decrease by 75 megatonnes of carbon dioxide equivalent between 2021 and 2030, with the largest decrease coming from electricity generation amid increasing agriculture and direct combustion emissions. In the no price scenario emissions are projected to increase by 104 megatonnes of carbon dioxide equivalent between 2021 and 2030, with the largest increase coming from electricity generation.

Source: Climate Change Authority calculations using results from The Treasury and DIICCSRTE 2013

D2.3 Sectoral contributions to emissions

State and Commonwealth regulation has been a major driver of emissions reductions. An 85 per cent reduction in LULUCF emissions was a key reason why Australia’s whole-of-economy emissions were relatively flat between 1990 and 2012. Emissions from electricity generation were growing quickly until 2009, when they started to decline. Since then, a reduction in grid-connected electricity demand, combined with lower emissions generation, has driven down the emissions from the National Electricity Market (NEM). The amount of electricity generated in Australia has remained relatively flat since 2007. Growth in lower emissions generation, including large-scale renewable generation, has displaced traditional emissions-intensive generation sources and has driven down the emissions intensity of electricity supply.

Under the low, medium and high scenarios, reductions in Australia’s emissions intensity between 2012 and 2030 are expected to be more distributed across the economy than in the past.

  • Electricity – emissions under the high scenario are projected to decline between 2012 and 2030, driven by lower demand growth, energy efficiency and a shift towards lower emissions intensity generation. The outlook under the low scenario and no price scenario is for emissions to rise by between 5 and 23 per cent between 2012 and 2030.
  • Transport – demand is expected to continue to grow, driven by strong growth in road freight and domestic aviation. Modest growth is projected in light passenger vehicle emissions, which are the largest contributor to transport emissions. Increasing use of low-emission fuels and vehicle efficiency improvements are projected to largely offset activity increases to 2030.
  • Direct combustion and fugitive emissions – projected to increase to 2030, particularly because of greater gas production driven by foreign demand for Australian liquefied natural gas (LNG) and coal. The growth in direct combustion and fugitive emissions could drive most of the net growth in domestic emissions to 2030 under the low scenario, more than offset the net reductions from the rest of the economy under the medium scenario, or significantly offset the net emissions reduction under the high scenario.
  • Industrial processes – under the low, medium and high scenarios, industrial process emissions are projected to fall by between 25 and 66 per cent from 2012 to 2030, largely due to the deployment of nitrous oxide conversion catalysts, which improve emissions intensity. Under a no price scenario, industrial process emissions are projected to rise by about 40 per cent above 2012 levels by 2030.
  • Agriculture and LULUCF – increasing export demand for Australian agricultural commodities is projected to drive an increase in emissions from agriculture. Projected emissions from LULUCF depend on the level of price incentive for emissions reduction.
  • Waste – emissions, in all scenarios, are projected to fall through improved waste management, specifically landfill gas capture and combustion (whether flared or used to generate electricity).

Figure D.8: Australian domestic emissions by sector, 1990–2030

Figure D.8 shows Australia’s historical and projected emissions by sector between 1990 and 2030. Australia’s emissions between 1990 and 2012 remained relatively steady, with a decrease in LULUCF and an increase in electricity generation emissions. In 2020, emissions are expected to be around 700 megatonnes of carbon dioxide equivalent in the no price scenario, 650 megatonnes of carbon dioxide equivalent in the low scenario, 620 megatonnes of carbon dioxide equivalent in the medium scenario and 550 megatonnes of carbon dioxide equivalent in the high scenario. In each scenario electricity generation is projected to account for the largest share of Australia’s emissions, followed by direct combustion and fugitive emissions.In 2030, emissions are expected to be around 800 megatonnes of carbon dioxide equivalent in the no price scenario, 670 megatonnes of carbon dioxide equivalent in the low scenario, 644 megatonnes of carbon dioxide equivalent in the medium scenario and 465 megatonnes of carbon dioxide equivalent in the high scenario. Electricity generation is projected to account for the largest share of Australia’s emissions in each scenario, except the high scenario where agriculture and direct combustion emissions are around equal largest.

Source: Climate Change Authority calculations using results from The Treasury and DIICCSRTE 2013

Appendix D3 Electricity

D3.1 Electricity emissions overview

Generating electricity using fossil fuels, such as coal, natural gas and liquid fuels, results in greenhouse gas emissions. Electricity generation supplying electricity grids, for example, the National Electricity Market (NEM), and electricity generation for private use (‘off-grid’) are included in this analysis.

Electricity generation emits the largest sectoral share of Australia’s greenhouse gases, producing 33 per cent of national emissions in 2012 (Figure D.9). Electricity generation is projected to remain the largest sectoral emitter until at least 2030, except in the high scenario. It is also projected to be the largest sectoral contributor to emissions reduction in the low, medium and high scenarios.

Figure D.9: Electricity generation sector emissions share – selected years, 1990–2030

Figure D.9 shows the historical and projected share of electricity generation emissions between 1990 and 2030. Electricity generation emissions increased from 130 megatonnes of carbon dioxide equivalent in 1990 to 198 megatonnes of carbon dioxide equivalent in 2012. In 2020, electricity generation emissions are projected to be 201 megatonnes of carbon dioxide equivalent in the no price scenario, 192 megatonnes of carbon dioxide equivalent in the low scenario, 185 megatonnes of carbon dioxide equivalent in the medium scenario and 142 megatonnes of carbon dioxide equivalent in the high scenario. In 2030, electricity generation emissions are projected to be 243 megatonnes of carbon dioxide equivalent in the no price scenario, 207 megatonnes of carbon dioxide equivalent in the low scenario, 192 megatonnes of carbon dioxide equivalent in the medium scenario and 70 megatonnes of carbon dioxide equivalent in the high scenario.

Source: Climate Change Authority calculations using results from The Treasury and DIICCSRTE 2013

After decades of growth, levels of electricity generation have been relatively stable since 2008. Since then, emissions declined by an average of almost 1 per cent each year to 2012. The Australian Energy Market Operator (AEMO 2013a) and The Treasury and DIICCSRTE (2013) project that electricity demand will start growing again to 2020 and continue to rise after that (Figure D.10).

Along with lower demand, the recent emissions decline was also due to a marked downturn in emissions intensity of supply between 2008 and 2012 (BREE 2013c, The Treasury and DIICCSRTE 2013). ACIL Allen Consulting (2013) projects that this trend towards lower emissions intensity may continue in the low, medium and high scenarios, but could stall from 2020 in the no price scenario (Figure D.11).

Figures D.10 and D.11 show an outlook for a continued decline in electricity sector emissions under all but the no price scenario. The Treasury and DIICCSRTE modelling suggests that higher electricity demand could be offset by a lower emissions intensity of supply in the low, medium and high scenarios. In contrast, electricity emissions are projected to rise strongly in the no price scenario.

Figure D.10: Electricity generation activity and emissions intensity of electricity supply – modelled range, 1990–2050

Figure D.10 shows historical and projected electricity generation activity and the emissions intensity of electricity supply between 1990 and 2050. Between 1990 and 2012 activity rose from 155 to 248 terawatt hours and is projected to increase to between 378 and 492 terawatt hours in 2050. Between 1990 and 2012 the emissions intensity of electricity supply stayed around 0.8 tonnes of carbon dioxide equivalent per megawatt hour and is projected to improve to between 0.1 and 0.7 tonnes of carbon dioxide equivalent per megawatt hour in 2050.

Note: Upper and lower line bounds illustrate range of modelled outcomes. Electricity generation activity is ‘as generated’.
Source: Climate Change Authority calculations using BREE 2013c and results from The Treasury and DIICCSRTE 2013

Figure D.11: Electricity generation activity and emissions intensity – four scenarios, 1990–2050

Figure D.11 shows historical and projected electricity generation activity and the emissions intensity of electricity supply across four scenarios between 1990 and 2050. Between 1990 and 2012 activity increased while the emissions intensity of the electricity supply remained relatively steady. Activity is projected to continue increasing to 2050 across all scenarios while the emissions intensity of electricity supply is projected to continue decreasing to 2050 in all scenarios except the no price scenario.

Note: Electricity generation activity is ‘as generated’.
Sources: ACIL Allen Consulting 2013, BREE 2013c, Climate Change Authority calculations using results from The Treasury and DIICCSRTE 2013

This Section describes the most substantive contributors and drivers of the emissions outcomes projected for the electricity sector. Results of four scenarios (no price, low, medium and high) are presented, as modelled by The Treasury and DIICCSRTE. These scenarios are described in Chapter 10 of the Targets and Progress Review.

Sections D3.1.1 and D3.1.2, respectively, analyse in detail the potential changes in emissions intensity and activity. The focus of Appendix D3 is on grid-connected electricity, which accounts for about 96 per cent of total electricity generation, but offgrid electricity generation is analysed specifically, where appropriate (ACIL Allen Consulting 2013, in 2011–12).

Figure D.12 shows that in the no price scenario, modelling projects significant growth in electricity sector emissions, rising from 2012 levels (198 Mt CO2-e) to be 14 per cent higher than 2000 levels in 2020, and almost 40 per cent above 2000 levels in 2030.

Targeted policy could substantially reduce the sector’s emissions. If a price incentive is in place, The Treasury and DIICCSRTE projects that:

  • In 2020, Australia’s electricity sector emissions are reduced from their current 198 Mt CO2-e to between 142 and 192 Mt CO2-e (high and low scenarios, respectively). For the low and medium scenarios, this is a moderate increase on 2000 emissions levels, but for the high scenario it represents a 19 per cent reduction.
  • In 2030, electricity sector emissions trends depend significantly on what policy drivers are in place. Emissions could rise again to between 192 and 207 Mt CO2-e in 2030 (under medium and low scenarios, respectively) or fall under the high scenario to 70 Mt CO2-e in 2030 (60 per cent below 2000 levels).
  • In 2050, the low and medium scenarios could result in emissions reducing to about 110 Mt CO2-e (35–40 per cent below 2000 electricity emissions levels), while emissions may be as low as 34 Mt CO2-e under the high scenario (81 per cent below 2000 levels).

Figure D.12: Contributors to electricity sector emissions, 1990–2050

Figure D.12 shows the historical and projected contributors to Australia’s electricity sector emissions between 1990 and 2050. From 1990 to 2012, electricity sector emissions increased from 130 to 198 megatonnes of carbon dioxide equivalent. Electricity sector emissions are projected to be between 34 and 331 megatonnes of carbon dioxide equivalent in 2050. Between 1990 and 2012 black coal contributed over half of Australia’s electricity sector emissions and this is projected to remain so across all scenarios to 2050, except the high scenario. Relative to 2000, electricity demand was the main contributor to Australia’s lower emissions in 1990 and increased emissions in 2012. Increased electricity demand is projected to continue contributing to Australia’s emissions across all scenarios to 2050, except the high scenario. At the same time adoption of renewable technologies, such as solar, are projected to make a net negative contribution to electricity sector emissions across all scenarios.

Source: Climate Change Authority calculations using results from The Treasury and DIICCSRTE 2013

Figure D.13 shows that changes in electricity generation activity and the emissions intensity of supply are both important to delivering emissions reductions. From 2020 to 2050, in the high scenario, potential emissions reductions comprise comparable shares of shifting to lower emissions sources of generation, which reduce emissions intensity of supply, and reduced electricity demand.

The share of sectoral emissions reduction from decreasing electricity demand is greater under the low and medium scenarios, especially to 2030. By 2050, the emissions reduction opportunities are an approximately equal share of reduced demand and improved emissions intensity.

Figure D.13: Potential emissions reduction relative to the no price scenario, 2020–2050

Figure D.13 shows the potential emissions reductions of the electricity sector relative to the no price scenario between 2020 and 2050. In 2020, changes in activity contribute between 50 per cent and 100 per cent of projected emissions reductions with any balance due to improvements in emissions intensity. In 2030, changes in activity contribute between 39 and 86 per cent of projected emissions reductions with the balance due to improvements in emissions intensity. In 2050, changes in activity contribute between 46 and 50 per cent of projected emissions reductions with the balance due to improvements in emissions intensity.

Source: Climate Change Authority calculations using results from The Treasury and DIICCSRTE 2013

D3.1.1 Changes in electricity generation emissions intensity

Emissions intensity declined by about 7 per cent between 2000 and 2012 with further improvement expected in all modelled scenarios. The Treasury and DIICCSRTE projects that, in a no price scenario, the improvement is relatively modest; emissions intensity is projected to be about 16 per cent lower than 2000 levels in 2020 – primarily as a result of renewables and driven by the RET – but is likely to change little after that.

With incentives in place to reduce emissions, changes in the electricity supply mix could reduce the emissions intensity of supply by up to a third in 2020 and by almost 90 per cent by 2050, compared to 2000 levels (Table D.1).

Table D.1: Emissions intensity of Australia’s electricity supply, 2000–2050

 

Historical emissions intensity
(t CO2-e/MWh)

Projected emissions intensity
(t CO2-e/MWh)

Scenario

2000

2008

2012

2020

2030

2040

2050

No price

0.84

 

0.84

 

0.78

 

0.70

0.69

0.69

0.67

Low

0.70

0.66

0.48

0.28

Medium

0.69

0.62

0.47

0.26

High

0.56

0.25

0.10

0.09

Note: Calculated based on electricity generation ‘as generated’.
Source: Historical: BREE 2013c, Table O; DCCEE 2012. Projections: Climate Change Authority based on the Treasury and DIICCSRTE 2013 data and ACIL Allen Consulting 2013

Figure D.12 shows that several contributors affect the level of emissions by changing the electricity supply mix, particularly:

  • declining conventional coal-fired generation, which could reduce emissions by between 2 and 56 Mt CO2-e in 2020, relative to 2000 levels. Emissions from coal-fired generation are projected to be higher in 2030 than in 2000, except under a high scenario where they could be almost 130 Mt CO2-e lower; and
  • increasing wind and solar generation share, which could contribute to an emissions reduction of about 30 Mt CO2-e in 2020, relative to 2000. Projections suggest that in 2030 increasing wind and solar generation share could reduce emissions by between 39 and 51 Mt CO2-e (in no and high scenarios, respectively), relative to 2000.

Carbon capture and storage (CCS) and geothermal generation could also contribute significantly in later decades, though timing of their deployment remains uncertain. Table D.3 provides further detail of the potential fuel mixes that could lower the emissions intensity of electricity.

The deployment and diffusion of electricity generation technologies will depend on a range of drivers. Exchange rates, technological advances, climate change mitigation policy and electricity prices will affect the relative cost of technologies and the point at which each option becomes economically viable. Until 2020, the mandatory RET is likely to drive steady deployment of renewables, such as wind. Appendices D3.3 and D3.4 discuss further the opportunities and barriers to realising the potential changes in emissions intensity.

D3.1.2 Changes in electricity demand

Since 2008, growth in electricity generation has softened (Table D.2). The Treasury and DIICCSRTE’s modelling projects that Australia’s electricity generation will rise steadily to 2020 and more quickly to 2030, in all scenarios. Even in 2020, the effect of the price incentive on projected generation is evident; electricity generation is about 6 per cent lower in 2020 under the high scenario than the medium scenario. By 2050, electricity generation could be between 80 and 89 per cent higher than in 2000, depending on the level of the price incentive (high and low scenarios, respectively).

Macroeconomic drivers, weaker global financial conditions and a rising Australian dollar have underpinned softening demand in the industrial sector, with the closure of the Kurri Kurri aluminium smelter in 2012 being one example (AEMO 2013a). Future industrial sector demand for electricity is likely to rise with strong projected growth in activity, but continuation of current energy efficiency improvements could offset growth to some extent (ClimateWorks 2013c).

Changes in electricity demand are driven, in part, by rising incomes and population, which have historically resulted in increased use of electric appliances. Over the last two decades, the increased emissions that might be expected from the uptake of new appliances, such as information technology and entertainment equipment, has been counteracted by improved efficiency in buildings and electrical appliances. Efficiency improvements have been driven primarily by policy intervention at various levels of government, particularly minimum energy performance standards for appliances implemented from 1999, and changes to the Building Code of Australia for residential buildings. Uptake of small-scale solar PV has also reduced demand for grid-connected electricity.

Recently, substantial rises in electricity prices – growth of almost 60 per cent in residential prices from 2008–2012 – have contributed to reduced growth in demand. This driver, however, could moderate within a few years (AEMO 2013a, p. 21).

Table D2: Australia’s electricity generation, 2000–2050

 

Historical electricity generation
(
TWh)

Projected electricity generation
(
TWh)

Scenario

2000

2008

2012

2020

2030

2040

2050

No price

210

 

243

 

254

 

287

351

422

493

Low

275

312

344

398

Medium

269

312

346

401

High

253

282

329

378

Note: Electricity generation is ‘as generated’.
Source: Historical: BREE 2013c, Table O. Projections based on ACIL Allen Consulting 2013

Some of the major contributors expected to reduce future emissions, through changing demand in the residential and commercial sectors, are:

  • improvements in building efficiency, which could reduce emissions, relative to 2000 levels, by about 12 Mt CO2-e in 2020 and more in later years as stock turns over; and
  • improvements in the efficiency of electric appliances, which could reduce emissions, relative to 2000 levels, by about 20 Mt CO2-e in 2020 and more in later years (DCCEE 2010b, p. 23).

Section D3.3 discusses further the opportunities and barriers to the uptake of cost-effective emissions reductions through changing electricity demand and reducing the level of total generation.

D3.2 Emissions intensity of electricity supply

D3.2.1 Emissions intensity outcomes in an international context

Table D.1 summarised projections for Australia’s emissions intensity, which, in all scenarios, reflect some improvement on current and historical levels.

Australia’s emissions intensity of electricity is among the highest in the developed world (Figure D.14). According to the IEA (2013b, p. 111), Australia’s electricity emissions intensity is about four times the intensity of New Zealand and Canada; almost double the intensity of Germany, the UK and Japan; and considerably higher than that of the United States. Since 2007, Australia’s electricity supply emissions intensity has exceeded China’s (IEA 2013b, p. 111). Despite projected improvements in Australia’s emissions intensity, the improvements projected by the IEA in other countries mean that Australia’s emissions intensity is likely to remain above China’s, the United States’ and the world average in 2035. Only the high scenario projects Australia’s electricity emissions intensity to be below levels projected by the IEA in China, the US and for the world in 2035 (IEA 2012a, p. 196, 198; The Treasury and DIICCSRTE 2013).

Figure D.14: Emissions intensity of electricity supply for selected countries, 2000–2035

Figure D.14 shows the emissions intensity of electricity supply between 2000 and 2035 for Australia, Canada, China, Germany, Japan, New Zealand, the United Kingdom and the United States. Between 2000 and 2010 Australia’s emissions intensity of electricity supply was higher than the other countries except China. In 2035, Australia’s emissions intensity of electricity supply is projected to be higher than all the other countries despite a 31 per cent improvement in the emissions intensity of electricity supply.

Source: IEA 2013b, 2012a; Australia’s 2035 figure is based on Climate Change Authority calculations using results from The Treasury and DIICCSRTE 2013

D3.2.2 Contributors to emissions intensity of generation

With incentives in place, a range of modelling projections suggest that Australia’s electricity supply will become less emissions-intensive as conventional fossil fuel-fired generation loses generation share to low and zero emissions sources. Several technologies could contribute directly to a lower emissions intensity of supply. Figure D.12 shows that changes in the shares of conventional coal-fired generation and renewables could be particularly significant.

This is illustrated in ACIL Allen Consulting’s outlook for Australia’s electricity supply, based on particular assumptions under three scenarios, in Figure D.15. The projected generation mix is affected significantly by the level of the price incentive. The high scenario projects a substantial increase in the share of generation from renewables and a fall in the share of coal-fired generation. Coal with CCS is also deployed by 2030, bringing the emissions intensity of generation down to 0.25 t CO2-e/MWh. By contrast, the low scenario projects relatively modest changes to the supply mix, with emissions intensity of generation projected to be about 0.66 t CO2-e/MWh in 2030. The growth in renewable generation, driven primarily by the RET to 2020, is important in all scenarios, even in the no price scenario, where the generation mix is otherwise projected to be little changed.

Figure D.15: Share of electricity generation by fuel type, 2012–2050

Figure D.15 shows the projected share of electricity generation, by fuel type, between 2012 and 2050 in three scenarios. The main difference is that in the medium and high scenarios have a more diverse energy mix, with much more generation from low- and zero-emissions sources, including renewable energy and carbon capture and storage. In the no price scenario, black coal contributes over half of electricity generation in 2050, around 20 per cent in 2050 in the medium scenario and its contribution falls to around zero in the mid-2030s in the high scenario. In the medium and high scenarios, the largest contributor to electricity generation is solar in 2050.

Note: Based on electricity generation ‘as generated’.
Source: ACIL Allen Consulting 2013

Uncertainties about the timing and magnitude of declines in emissions-intensive electricity generation and growth in low-emissions generation, give rise to a range of potential electricity supply mixes for Australia. Table D.3 presents projected generation shares under a range of scenarios.

Table D.3: Share of electricity generation for selected fuels and technologies, 2000–2030 (no price, low, medium and high scenarios)

 

Historical

Projected

Fuel type

2000

2012

2020

2030

Coal (conventional)

83%

71%

48–67%

9–70%

Natural gas (conventional)

8%

15%

9–25%

8–14%

Coal and gas with CCS

Not available

Not available

Not available

Up to 7%

Potentially deployed as early as 2030 but late as mid-2040s

All renewables

9%

11%

21–24%

21–69%

Solar

Negligible

1%

3%

6–14%

Wind

Negligible

3%

11–12%

9–20%

Geothermal

Not available

Not available

Not available

Up to 28%

 

Note: Results are based on shares of generation ‘as generated’ for four modelled scenarios with various levels of price incentive, as described in Chapter 10. ‘Medium’ scenario is ‘central’ scenario in original source. ‘All renewables’ include hydro, wind, geothermal, biomass, solar PV and solar thermal. Solar water heating is not included.
Source: ACIL Allen Consulting 2013.

The supply mix will be different for off-grid electricity generation, and its emissions intensity is currently lower than for Australia as a whole. In 2012, almost 80 per cent of remote and regional generation was produced using gas, reflecting the high proportion of energy and resource operations located in areas supplied by gas pipelines.

Compared with the national average of almost 10 per cent, the share of renewables in off-grid generation was as little as 2 per cent. The share of renewables in off-grid generation is greatest in the southern states. In Tasmania, New South Wales, Victoria and the Australian Capital Territory, renewables account for 27 per cent of off-grid generation (BREE 2013d, p. 19). Indications are that gas generation will continue to dominate off-grid electricity generation (ACIL Allen Consulting 2013).

D3.2.3 Drivers of emissions intensity of generation

Several drivers will influence the deployment and diffusion of technologies that contribute to the emissions intensity of electricity supply. The primary determinant of the supply mix – and how quickly emissions-intensive generators decline and low-emissions generators grow – will be the relative cost of generation from different sources. Coal currently dominates Australia’s electricity supply because it has the lowest marginal costs of operation.

Multiple drivers change relative generation costs. Modelling suggests that policy is a critical influence. The presence of a price incentive for emissions reduction, and the level of that incentive, can change cost relativities significantly. This is evident from the greater share of low-emissions generation in scenarios with a price incentive and the effect of the RET, as currently legislated, on deployment of renewable sources is also apparent to the 2020s.

Other drivers include exchange rates, commodity prices, interest rates, and rates of deployment and learning. In the near term, the levelised cost of electricity (LCOE) from different technologies will also be driven by fuel costs and the value of RET certificates. The LCOE is also strongly influenced by the capacity factor – the ratio of a plant’s actual output to its potential output at full capacity - and this is taken into account when making investments. Given uncertainties about these many drivers, there is a range of estimates about costs of future generation. Figure D.16 reflects one view.

Figure D.16: Projected LCOE of selected generation technologies (with a carbon price), 2020–2040

Figure D.16 shows the projected levelised cost of electricity of selected electricity generation technologies (with a carbon price) in 2020, 2030 and 2040. In 2020 and 2030 solar thermal has the highest levelised cost of electricity and in 2040 shares the approximate highest price with brown coal. In 2020 and 2030 wind has the lowest levelised cost of electricity and shares the approximate lowest price in 2040 with solar PV. Forecast wholesale prices for the national electricity market, per megawatt hour, are projected to be below the levelised cost of electricity for most technologies.

Notes: Assumes a price incentive around the levels in The Treasury and DIICCSRTE’s 2013 medium scenario. Solar thermal is compact linear Fresnel reflector (CLFR) without storage, solar PV is fixed (no tracking). Brown coal prices are for Victoria; black coal, gas, wind and solar are for NSW; geothermal is in South Australia.
Sources: ACIL Allen Consulting 2013 medium scenario (‘central scenario’) (for NEM prices) and BREE 2012a (for LCOE)

To at least 2020, relatively stable demand for grid-connected electricity makes it unlikely that there will be significant investment in electricity generation, except in response to policy drivers such as the RET. During this period, existing generators, which have already amortised their initial capital investment, will be likely to continue to operate. This means that the risk of ‘lock in’ of new high-emissions generation is relatively low over the next decade. Longer term, as economic activity grows and electricity demand rises, new generation will be needed. Capital and regulatory hurdles aside, lower cost generation sources will be taken up more quickly and deployed more widely.

When the drivers that affect technology costs change, so do the projected electricity generation mix and projected emissions, as shown in Table D.4. Findings of ACIL Allen Consulting’s (2013) modelling sensitivities include:

  • Setting a higher price incentive for emissions reduction will see it occur to a higher marginal cost; the share of coal would fall more quickly and coal-fired plants retire sooner, and the share of low-emissions electricity generation, including renewables and CCS, could be larger.
  • A higher price for gas, oil and coal will have an uncertain effect on emissions. It will depend on the relative prices for these fuels at different times. Since fuel prices usually comprise a greater share of generation costs for gas-fired generators than coal-fired generators, higher fuel prices may disadvantage gas over coal-fired generators. Higher fuel prices would also disadvantage fossil fuel generators over renewables by the late 2020s, leading to a fall in emissions.
  • Faster cost reductions for solar photovoltaic (PV) would lead to greater deployment, probably at the expense of coal, with corresponding falls in emissions for at least two decades.

Another determinant of investment is the stability of policy and the amount of information available to investors in electricity generation assets. Clarity on incentives for emissions reduction is important. Uncertainty could lead to suboptimal investment in an electricity supply mix over the long term (Investment Reference Group 2011).

Investor confidence could be increased by publishing more information on the pipeline for grid-connected electricity generation assets. This data could also assist policy-makers. One way to do this may be through a rule change that allows AEMO and transmission companies to disclose connection applications from generation proponents, to avoid the risk of its public list of generation committed for construction being out of date or incomplete.

Table D.4: Effect of sensitivities on generation share and emissions, relative to medium scenario, in 2030

 

Wind

Solar

Gas (conventional)

Coal (conventional)

Coal (CCS)*

Emissions

Higher incentives for emissions reduction (‘high scenario’)

Higher fuel price (gas, coal, oil)

- /

-

- /

Geothermal and CCS unavailable

-

-

-

-

-

Faster learning rates or lower costs for solar PV

-

-

-

Higher electricity demand

-

-

-

- /

 

*Geothermal and CCS are not projected to be deployed at a significant rate by 2030 in the medium scenario, nor under any sensitivity, excepting the high scenario.
Note: Details on sensitivity assumptions can be found in ACIL Allen Consulting 2013. Changes are relative to projected generation in the medium scenario.
Source: ACIL Allen Consulting 2013

D3.3 Emissions reduction opportunities from existing generation

D3.3.1 Fossil fuel generation

To at least 2020, existing and committed electricity supply is expected to be adequate to meet demand in the NEM (AEMO 2013b). At present, it appears that for the next several years, stable electricity demand and uncertainty in policy and fuel prices is likely to make incremental or small-scale change in the electricity sector more appealing to investors. In the near term, the main opportunities to reduce the emissions intensity of the existing generation fleet may relate to:

  • reducing output;
  • retrofitting; and
  • fuel prices.
Reducing output

The recent trend in coal-fired generation has been for plants to reduce output rather than retire. Since 2009, over 2 000 MW of coal-fired generation has been mothballed and coal-fired asset utilisation was down, with black coal falling from 86 to 79 per cent between 2007 and 2013 (ClimateWorks 2013b, p. 25). As stable demand and policy uncertainty delay investment in large new sources of supply, this pattern may continue until the early 2020s.

It is possible that some generators would change business models to run plants as intermediary generation, or operate during summer when wholesale prices are generally higher, rather than close completely (Climate Change Authority industry workshops, August 2013). A wide range of modelling studies suggest this is possible, with conventional coal projected to remain in Australia’s electricity supply mix for decades, even if a price incentive to reduce emissions exists.

Exit costs could present a barrier to retirement of existing fossil fuel plant. Clean-up and remediation requirements, which take effect upon closure, could cost hundreds of millions of dollars, improving the case for operating for longer, even at reduced output (AECOM 2012, Colomer 2012).

There is a consistent outlook, across a range of modelling studies, that when a price incentive for emissions reduction exists, coal-fired generation is likely to fall. Table D.3 shows that ACIL Allen Consulting (2013) suggests that the share of generation from conventional coal could fall from its current levels (71 per cent) to as low as 48 per cent in 2020 and as low as 9 per cent in 2030. Timing is uncertain, but ACIL Allen Consulting (2013) projects the fall will occur in the late 2030s for black coal and as soon as the early 2020s for brown coal, in the low and medium scenarios. Under a high scenario, coal-fired generation would fall earlier and more sharply.

Retrofitting

Some fossil fuel generators may also be retrofitted to operate with lower emissions intensity. A number of Australian coal-fired generators have indicated plans to upgrade turbines, modify boiler operation and investigate coal drying technologies to improve thermal efficiency and reduce emissions (DRET 2013).

There also appears to be significant potential to retrofit existing fossil fuel plants with hybrid technologies. Co-firing with lower emissions fuels not only cuts generators’ emissions but also overcomes traditional barriers to renewable energy, including land availability, capital and transmission costs. An early step has already been taken by the 2 000 MW black coal Liddell Power Station, which has installed an 18 MW solar thermal array to heat water to create steam, thus reducing the need to burn coal for that purpose and cutting emissions by approximately 5 000 tonnes each year (EcoGeneration 2013). In addition, the power station can co-fire coal with biomass and recycled oil (Macquarie Generation 2012). In their Clean Energy Investment Plans submitted to the Commonwealth Government, other generators, including Loy Yang, indicate that they are investigating the potential for co-firing (DRET 2013).

Fuel prices

For existing fossil fuel generation technologies, fuel prices are a major determinant of cost and will affect how coal- and gas-fired generation contribute to Australia’s supply mix. As Australia’s gas production booms and eastern Australia prepares to export liquefied natural gas (LNG) for the first time, gas price rises are generally anticipated, though the timing and precise levels are uncertain (Wood and Carter 2013). In some scenarios, even with a price incentive in place, The Treasury and DIICCSRTE modelling suggests that projected increases in gas prices could make existing gas power plants more costly than coal-fired power. The modelling suggests a high gas price could cause the share of base load gas generation to fall below its share in today’s generation mix and below its projected share in 2020 or 2030 in the medium modelling scenario (see Appendix C). This trend could also occur if coal prices fell. Major electricity sector players report that it may not be economic to build a large new grid-connected gas-fired power plant for the foreseeable future (Climate Change Authority industry workshops 2013).

Overseas, lower cost gas is increasing its share in electricity generation by displacing coal, and reducing emissions as a result. In the US, increasing generation from natural gas contributed to a decline in emissions from electricity generation of 4.6 per cent in 2011 compared to the previous year (US EPA 2013). Australia’s gas prices are considerably higher – and likely to rise more in coming years – making this change in supply mix less likely.

The economic viability of new coal-fired generation facilities may also be undermined by difficulty in obtaining low-cost finance, if the international trend toward withdrawing finance to coal-fired generators extends to Australia. In mid 2013, the US Export-Import Bank, the World Bank and European Investment Bank, which together provided more than $10 billion for coal projects in the last five years, announced they would withdraw from financing conventional coal (Drajem 2013).

D3.3.2 Generation from renewable energy

ACIL Allen Consulting (2013) projects significant amounts of renewable generation under a range of scenarios (see Table D.3). The RET drives the deployment of renewable energy to 2020 in all scenarios, including the no price scenario. The addition of a carbon price in the low, medium and high scenarios results in significantly more renewable generation. Figure D.7 showed that after 2020, the increase in renewables is projected to be much greater with a higher price incentive to reduce emissions.

To 2020, much of the increase is expected to come from wind. Of the 3 000 MW of electricity projects at an advanced stage of development in late 2012, 65 per cent of the planned installed capacity was wind, reinforcing the view that wind will increase its share of the supply mix in the near term (BREE 2013a).

Box D.1: Climate change effects on electricity supply

Climate change will affect future opportunities to change the electricity supply mix and reduce emissions. The impacts of climate change, particularly water shortages and extreme weather, affect electricity demand, generation and transportation (Foster et al. 2013, Senate Environment and Communications References Committee 2013). Sources of generation that use large amounts of water, including geothermal, bioenergy, coal-fired and nuclear power, will be disadvantaged in a context with water shortages (IEA 2013c).

Over the last decade, Australian electricity supply has been disrupted by floods and bushfires. The output of hydroelectric generators and coal-fired generators, which use large amounts of water for steam production and cooling, has been reduced and could fall again with drought. With water shortages and more extreme climate events expected (see Chapter 2 of the Review), the extraction of coal and unconventional gas, generation from certain sources, and the transmission and distribution of electricity could be disrupted more often (IEA 2013c, US DoE 2013).

Longer term, solar generation is projected to play a large role in Australia’s future generation mix in scenarios with a price incentive to reduce emissions. In the medium scenario, The Treasury and DIICCSRTE suggest that solar generation could increase its share from about 3 per cent in 2020 to about 20 per cent in 2040, and 25 per cent in 2050. Most of the expected growth is large-scale generation.

If costs continue to fall, solar PV is projected to become increasingly cost-competitive with investments in conventional sources of generation. ACIL Allen Consulting (2013) modelled a sensitivity that reduced the costs of large-scale solar PV by 10 per cent to 2020 and 5 per cent to 2030. The results showed that solar PV could generate about 10 500 GWh electricity in 2020 and 59 000 GWh in 2030 (almost six and 35 times as much when compared to 2012, in 2020 and 2030 respectively).

Australia’s solar resource is one of the best in the world and theoretically capable of generating enough electricity to meet Australia’s demand (Geoscience Australia and ABARE 2010). Solar PV systems might offer consumers financial savings by reducing consumption of grid-connected electricity. The value of solar PV is likely to be greatest for users with an electricity demand profile that matches system output, such as commercial premises (Wood et al. 2012). Solar PV’s low reliance on water makes it viable even in dry and remote locations, and in a future with potential disruption to water supply (see Box D.1). BREE’s pipeline of electricity generation projects reinforces its promising future (2012b, p. 16).

D3.4 Reducing emissions with emerging generation and storage options

Current excess generation capacity, combined with uncertainty about emissions reduction policy and fuel costs, makes it unlikely that new electricity generation technologies will emerge in Australia, at scale, before at least 2020. Large uncertainties remain about the timing, costs and viability of new low-emissions sources of electricity generation, particularly for CCS and geothermal. This is reflected in recent ACIL Allen Consulting modelling results, which suggest a lesser role for these technologies in contrast with earlier modelling of the outlook for the Australian electricity sector (for example, SKM-MMA 2011 and ROAM 2011). ACIL Allen Consulting (2013) modelling suggests that in the low or medium scenarios, neither CCS nor geothermal will contribute a significant share of generation until around 2040. The high scenario suggests, however, that geothermal and CCS may emerge as early as 2017 and 2030, respectively. The technology and business models necessary to widely deploy electric storage are also changing rapidly, making cost and uptake highly uncertain.

D3.4.1 Carbon capture and storage for coal-and gas-fired generation

CCS is not yet operating at a large scale1 for electricity generation anywhere in the world, though it has been deployed in the gas processing and industrial sectors (see Appendix D6, for example). The gradual progress in developing large-scale projects is evident in the Global Carbon Capture and Storage (CCS) Institute’s status reports (2013c, p. 2) – in January 2013, the number of operational projects was the same as in 2010 and the total CO2 capture capacity of all identified large-scale integrated projects had fallen over the past three years. In 2013, the IEA warned that current efforts to develop CCS are ‘insufficient’ and called for ‘urgent action … to accelerate its deployment’ (2013a, pp. 1, 10). The IEA suggests that multiple demonstration projects, each sequestering about 0.8 Mt CO2-e annually, are needed this decade if CCS is to fulfil its emissions reduction potential, consistent with limiting average global temperature increases to 2 degrees Celsius (2013a, p. 9).

There are two key challenges to the widespread deployment of CCS for electricity generation. The first is financial – the significant cost to build and operate the technology at a large scale (IEA and GCCSI 2012). The minimum cost for a large-scale CCS plant in Australia will likely be several billion dollars (GCCSI 2013d). The financial barrier may be overcome if an additional revenue stream is available to offset costs of the project, such as enhanced oil recovery (EOR) or a commercial application in other production processes, or if public or policy support is available (GCCSI 2013b).

The second key challenge is the integration of technological components at scale (IEA and GCCSI 2012). The logistical, practical and commercial challenges are likely to be overcome as experience grows, and the number of pilot CCS projects already illustrate this.

There is broad consensus that CCS technology will be first commercially deployed overseas, and Australia will be a ‘technology taker’. Australia, with its unique geology, cannot rely on international developments to facilitate storage, however. International developments are likely to set timing of commercial CCS deployment in Australia; in particular:

  • China may be well placed to overcome the challenges to CCS. The Chinese Government has expressed strong support for deployment of CCS – for thermal power (and other sectors) – in many of its significant strategic development and scientific documents. China is the only global region where the number of large-scale integrated CCS projects increased between 2011 and 2013, many of them driven by state-owned energy companies (GCCSI 2013a, 2013c).
  • North America has about 70 per cent of the world’s active large-scale integrated CCS projects, including Canada’s Boundary Dam and Mississippi Power projects, expected to operate from early 2014 (GCCSI 2013c, p. 5; BNEF 2013). Success with these two projects would be an important milestone towards the commercialisation of CCS and would be likely to lead to cost reductions. North America has particular potential because of its high level of committed public support, the commercial opportunities for EOR and an existing CO2 pipeline, which together lower costs and commercial risk (Abellera 2012). New emissions intensity regulations for power plants could provide further incentive.

D3.4.2 Geothermal energy

Australia’s geothermal resource is relatively deep and it is uncertain how and when energy can be extracted reliably, at reasonable cost. Its development remains at the exploration and demonstration stage; the most developed project is the 1 MWe Habanero Pilot Plant in South Australia, which produced Australia’s first Enhanced Geothermal Systems (EGS) generated power during a 160-day trial in 2013. However, engineering challenges remain for Australia’s geothermal energy, including repeatedly creating heat reservoirs, improving drilling practices and equipment, and enhancing flow rates (Wood et al. 2012).

A major barrier for the development of geothermal generation is the capital outlay needed to trial technology at a large scale. Present estimates suggest a 100 MW hot sedimentary aquifer (HSA) geothermal plant could cost around $700 million (BREE 2012a, p. 54). Government funding has played a central role in Australia’s development of geothermal to date. The Australian Renewable Energy Agency (ARENA) has committed funding towards demonstration of larger power stations which, if taken up, could provide an opportunity to better understand project costs and the ability to overcome engineering challenges at scale.

D3.4.3 Nuclear fission

Under different circumstances, nuclear fission could play a role in a low-emissions electricity supply mix, as it does overseas. This is apparent in analyses, such as the CSIRO eFutures, that make nuclear fission an available option in Australia’s generation mix in a scenario with a moderate emissions reduction incentive in place. Even if nuclear power was legalised in Australia, a range of barriers to its deployment, identified by the Uranium Mining, Processing and Nuclear Energy – Opportunities for Australia report in 2006, appear to remain (Commonwealth of Australia):

  • Regulatory and planning requirements – in 2012, Wood et al. concluded that ‘the lead time to deploy a nuclear power plant in Australia is between 15 and 20 years’ because of the need to create legal and regulatory frameworks, and because of time necessary for planning and construction (p. 71).
  • Community opinion – It seems that public support would be essential for nuclear power to be viable, though at present public acceptance remains uncertain and has historically been hostile to the domestic development of nuclear energy (National Academies Forum 2010).
  • Workforce availability – Australia lacks personnel with the knowledge and capability to plan, construct and operate nuclear power generation. There is also a looming global shortage of these skills (Commonwealth of Australia 2006; OECD 2012).

Nuclear project costs for Australia are uncertain, but high costs appear a barrier to deployment in the near term. Cost estimates vary widely, influenced significantly by investor perceptions of risk. Recent estimates for developed country nuclear energy projects range from $3–6 million per megawatt (overnight cost, in Wood et al. 2012, p. 711). These costs are high compared to other existing sources of generation. A report prepared for the Prime Minister in 2006 concluded that to be competitive with existing generation, nuclear power would require a carbon price (Commonwealth of Australia, p. 6). Like geothermal and CCS, nuclear power is capital-intensive and may be difficult for the private sector to finance (Citigroup Global Markets 2009; Commonwealth of Australia 2006).

At present, it seems doubtful that planning and capital requirements for nuclear power could be overcome soon enough for it to compete with other low-emissions technologies for which costs are falling, such as solar thermal with storage. If small modular reactors become commercially viable in the short term, however, they could offer a less costly form of nuclear technology (BREE 2012a).

D3.4.4 Electric storage

Modular storage lends itself well to supporting the generally modest changes in Australia’s electricity supply and demand expected over the next decade. Storage options include batteries, including those in electric cars, and compressed air storage. Affordable storage could dramatically improve the economic viability of renewables with variable generation, particularly off-grid (Marchment Hill Consulting 2012). CSIRO analysis suggests that the availability of storage as a backup technology could contribute up to an additional 10 per cent to renewable share and about 20 Mt CO2-e to emissions reduction (Graham, Brinsmead and Marendy 2013, p. 17).

Storage has been used successfully at scale, such as in Australia’s Smart Grid, Smart City project, but remains relatively costly. A recent EPRI study suggested break-even capital costs of energy storage of between $1 000 and $4 000 per kilowatt (2013, p v). If battery costs continue to fall, storage could become more widespread.

As with other emerging technologies, overseas developments are relevant to Australia. If California’s target for up to 1.3 GW of storage is realised by 2020, then cost improvements are likely to occur (Reddall and Groom 2013). Australia could also learn from successful overseas business models. In New Zealand, for example, electricity distribution network businesses are deploying and operating solar PV and battery storage systems, with leasing arrangements that are popular with households (Parkinson 2013). Change to energy market regulation in Australia could encourage distribution businesses to invest in storage when cost-effective (see Table D.5).

The analysis of electricity sector in this Review is based on modelling and other sources that assume a broad continuation of the existing centralised structure of Australia’s electricity supply. If electric storage and small-scale generation increase their rate of uptake, future reviews of progress should give greater consideration to a potential transition to a more decentralised energy system.

Box D.2: A zero-emissions supply mix by 2050?

Modelling by The Treasury and DIICCSRTE, and others, illustrates a potential supply mix where the electricity sector and other sectors of the economy together respond to emissions reduction incentives, at lowest cost and within existing policy parameters. Other studies consider a possible zero-emissions electricity supply mix. The independent operator of Australia’s national electricity market, AEMO, published an exploratory study of a 100 per cent renewables mix, which suggested that there are no technical barriers to such an outcome by 2050. AEMO’s study suggested that scenario could be possible without any electrical storage, though it could require ‘generation with a nameplate capacity of over twice the maximum customer demand’ or a large contribution from biofuel, which faces considerable barriers (2013c, p. 4).

With growing deployment of renewables, there is evidence that a generation mix dominated by renewable energy is technically possible. King Island, for example, produces 65 per cent of electricity consumed from renewables, primarily wind. They plan to move toward 100 per cent, combining this generation with solar, biodiesel, battery storage and smart grid technologies (GuevaraStone 2013). Other studies of high penetration of intermittent renewables, such as solar PV, have found that solutions to grid integration issues, such as new system invertors or electric storage, are available – though at a cost (Brundlinger et al. 2010; Energy Networks Association 2011).

D3.5 Electricity demand

D3.5.1 Activity emissions outcomes

Activity throughout the economy will affect the levels of electricity demand and will directly impact the level of emissions. Historically, growth in electricity sector emissions has increased as a result of strong growth in electricity demand (thus increasing total generation levels). From 1990 until a few years ago, Australia’s rate of increase in electricity generation was higher than most developed countries and well above the OECD average growth (IEA 2013b, p. 108). In 2011, Australia’s annual electricity consumption, per person, was about 11 MWh, above the OECD average of 8 MWh – though lower than the electricity-intensive economies of Canada and the United States (IEA 2012b, pp. 70, 74).

The outlook is for Australia’s short-term growth in electricity demand to increase (driven largely by the Queensland resource sector), as illustrated for the NEM in Figure D.17. Many electricity industry stakeholders suggest that, based on their observations of drivers of electricity demand, the low demand scenario from AEMO is more likely than its medium demand scenario, and even this growth may be an overestimate (Climate Change Authority industry workshops, August 2013). Only under The Treasury and DIICCSRTE high scenario is electricity demand projected to remain stable or fall between 2012 and 2020.

Even though overall electricity demand is expected to grow, per person electricity consumption is projected to fall to about 9.8 MWh in 2030 in the medium scenario. By contrast to NEM and total Australian electricity demand, it is likely that off-grid electricity generation will grow more rapidly, as it has in recent years, driven largely by an increasing number of remote resource projects.

Figure D.17 reinforces the fact that changes in electricity generation activity are affected by the level of a price incentive to reduce emissions, and resulting decreases in demand could provide significant emissions reductions. As Figure D.13 shows, in 2020 and 2030 more than 40 per cent of projected emissions reductions could result from lower electricity demand (compared to a no price scenario).

Figure D.17: Projected change in National Electricity Market demand and per person electricity consumption, 2013–2030

Figure D.17 shows the projected change in electricity demand in the National Electricity Market and per person electricity consumption between 2013 and 2030 across different scenarios. In 2013, electricity demand is projected to be between around 177,000 and 189,000 gigawatt hours, increasing to between around 194,000 to 224,000 gigawatt hours in 2030. In Treasury’s high scenario, electricity demand could decrease in 2020 (to around 180,000 gigawatt hours) before rising again in 2030. Demand per person in the medium scenario is projected to stay between 8 and 9 megawatt hours per person between 2013 and 2030, but projected to fall over that period.

Note: Based on sent out generation for NEM only (which accounts for about 86% of total domestic demand) (ACIL Allen Consulting 2013, for 2011–12).
Sources: AEMO 2013a; Climate Change Authority calculations using results from The Treasury and DIICCSRTE 2013 and the medium scenario from ACIL Allen Consulting 2013

D3.5.2 Contributors and drivers

Electricity demand is the function of a long list of drivers. Near term influences on electricity demand are as diverse as the time of year, weather, use of electric appliances and personal income. Longer term drivers include population growth composition and geographic distribution, electricity prices, economic growth, interest rates and exchange rates, climate change impacts, renewal of building stock, and commercial and industrial activity (Yates and Mendis 2009, p. 112).

Industrial demand

In the medium scenario, ACIL Allen Consulting (2013), AEMO (2013a) and The Treasury and DIICCSRTE (2013) project stable or modestly increasing industrial electricity demand due to:

  • new activity in major LNG projects in Queensland, coming online from 2014 to 2016;
  • declining activity in energy-intensive manufacturing, particularly aluminium production, as existing contracts for relatively low-priced electricity end;
  • potential reductions demand through improvements to processes and technologies; and
  • additional changes in the composition of the economy, which will see some electricity-intensive industries contract and others expand.

Industrial activity will be driven by several underlying factors, including commodity prices, exchange rates, fuel prices, management processes and the age of infrastructure.

It is possible that continued efficiency improvements will reduce industrial electricity use and associated emissions. If the improvements in industrial energy efficiency since 2007–08 are maintained, ClimateWorks estimates that it could reduce electricity sector emissions by about 6 Mt CO2-e between 2012 and 2020 (ClimateWorks 2013c, pp. 6, 13).

A sizable portion of industrial electricity demand is not connected to major electricity grids. BREE reports that the resources and energy sectors, for example, consume off-grid electricity equivalent to about 5 per cent of total national electricity demand (2013d, p. 7). This shift toward off-grid electricity generation is expected to continue (ClimateWorks 2013c).

Residential and commercial demand

Since around 2008, electricity demand has been flat, despite economic and population growth. Recently, residential, commercial and light-industrial demand for grid-connected electricity has fallen, contributing to emissions reduction. As described in Chapter 7, this has been driven by energy efficiency policy interventions, an increase in household solar PV generation and energy conservation behaviour in response to higher electricity prices since around 2008 (AEMO 2013a; DCCEE 2012). While projected growth in population and GNI will put upwards pressure on future electricity consumption, other drivers will dampen demand. Though it is possible the rebound effect could increase demand to some extent, policy and consumer behaviour make it possible that residential and commercial demand, per person, may have peaked for the foreseeable future:

  • Energy performance standards for buildings and electric appliances are becoming more stringent and are steadily expanding to cover new products. At the same time, those that been in place for many years are having a noticeable impact over time as the stock of appliances and buildings is turned over and the most inefficient, energy-intensive stock is phased out. AEMO reports that, in 2029–30, minimum energy performance standards for electrical appliances could save about 42 TWh and building-related energy efficiency measures could save about 16 TWh electricity (AEMO 2013d, pp. 546, 547). The impact could be increased by improving the monitoring and enforcement of building and appliance standards to ensure that they deliver intended energy saving outcomes (DCCEE 2010a).
  • Driven by standards but also changing preferences, consumers are beginning to move towards less energy intensive appliances. Large energy savings can come from technology switching, such as replacing plasma with LCD and LED televisions; incandescent with fluorescent and LED lighting; conventional electric-resistive water heaters with solar and heat pump systems; and desktop computers with laptops and tablets.

Consumers could reduce demand further if governments and regulators make available the information, price incentives and technological developments proposed in D3.5.3.

Potential new sources of electricity demand

It is possible there could be emerging sources of electricity demand from activities that currently use other sources of energy. The uptake of electric vehicles in road transport, already underway, may appreciably increase grid electricity demand from around the mid 2020s. Under the high scenario, where there is a stronger incentive for electric vehicles, electricity consumed for transport in 2050 could be almost double that consumed under all other scenarios (The Treasury and DIICCSRTE 2013). Similarly, a shift from gas turbines and motors towards electric motors in industry, could increase electricity demand. This could see activity and emissions shift from the transport and direct combustion sectors, respectively, to the electricity sector. The relative prices of fuels – petrol, diesel, gas and coal, and electricity – are likely to drive the rate and timing of these shifts. It is possible that desalination will also present a new source of electricity demand, particularly in a future where water is likely to be more scarce (Foster et al. 2013, p. 168).

D3.5.3 Further opportunities for cost-effective emissions reduction

The opportunity to reduce emissions from lowering electricity demand is particularly important in the short term. The IEA’s modelling offers a perspective on the global potential – it projects that energy efficiency measures, through improved lighting and appliances, could provide about 40 per cent of estimated global emissions reductions in 20202 (2013c, p. 54).

The modelling framework does not reflect all the opportunities to reduce electricity demand. International experience and other analyses show that there are unrealised opportunities to reduce electricity sector emissions by reducing electricity demand through energy efficiency. Compared to countries with similar GDP per capita and human development index rankings, Australia lags on energy efficiency and productivity. The IEA reported that, in both 2009 and 2011, Australia has been behind other countries including the United States, UK, Japan and Canada in implementing applicable IEA recommendations (IEA 2012c, p. 478). Though Australia performs comparatively well on lighting, appliance and equipment improvements, the IEA noted that buildings offer a particular opportunity for improvement leading to emissions reductions from electricity (2012c, p. 1223). Box D.3 discusses the size of this potential.

Changing energy demand could offer some of the lowest cost opportunities for reducing electricity sector emissions (ClimateWorks Australia 2013a; Garnaut 2008; Prime Minister’s Task Group on Energy Efficiency 2010). Not only can it be flexible and quick to implement, but savings can be significant.

Energy efficiency could deliver economic benefits, as highlighted by the IEA (2013c) and others, by avoiding costs for fuel extraction, transport, generation and transmission. Reduced demand can lead to lower electricity prices and substantial financial benefits for consumers. For Australia as a whole, the Climate Institute argued that an extra one per cent annual improvement in energy efficiency to 2030 could generate an additional $26 billion in GDP (2013, p. 7).

Demand management – where consumers’ consumption is constrained or shifted to a different time, particularly when demand is at its peak – also offers economic benefits. Sometimes it can also improve service quality, by reducing pressure on the electricity distribution grid. The Productivity Commission (2013, p. 21) estimated that critical peak pricing and other benefits from rolling out smart meters could save some households $100–$200 a year. The AEMC (2012) estimated that reducing peak demand growth could cut total system expenditure by between $4.3 and $11.8 billion over the next decade. If demand is simply shifted, the impact on emissions is uncertain, but overall reductions could lower electricity sector emissions.

Box D.3: Emissions reduction opportunities in buildings

About 18 per cent of Australia’s emissions are accounted for by buildings’ use of grid-supplied electricity. Slightly more than half of total building sector emissions are attributable to residential buildings, with the remainder attributable to commercial premises (ClimateWorks Australia 2013c, p. 12).

In buildings, the bulk of emissions are attributable to heating, ventilation and air conditioning (HVAC), water heating, refrigeration, lighting and other appliances. These can be offset by improvements in the thermal performance of the building shell, improvements in the efficiency of equipment, appliances and generation of energy onsite from renewables (such as solar PV) or gas:

  • improvements in building efficiency could reduce emissions, relative to 2000 levels, by about 12 Mt CO2-e in 2020; and
  • improvements in the efficiency of electric appliances could reduce emissions, relative to 2000 levels, by about 20 Mt CO2-e. The greatest savings are likely to come from water heaters, lighting, HVAC systems, motors and other electric equipment (ClimateWorks Australia 2013c, p. 13; Wilkenfeld 2009).

Many of these opportunities are likely to be low cost or have a positive net present value (Beyond Zero Emissions 2013; ClimateWorks Australia 2010, 2013c; IEA 2012b, 2013c).

D3.5.4 Challenges to more efficient electricity demand

ClimateWorks analysis suggests that, with current policy settings, many of the cost-effective reductions in electricity demand may remain untapped. Their projections suggest 29 Mt CO2-e of emissions reductions in 2020 and millions of dollars in annual financial savings could be forgone in the buildings sector alone (ClimateWorks Australia 2013a, p. 51; 2013c, p. 14). 

There is a range of recognised barriers to the take-up of cost-effective reductions in electricity demand, identified by the Productivity Commission (2005), Garnaut (2008) and others. Recent analyses, including the Australian Energy Market Commission’s 2012 Power of Choice review, have found that many barriers remain. Barriers and their potential solutions are shown in Table D.5.

There is considerable consensus about the solutions set out in Table D5, but implementation has not occurred. Despite the Council of Australian Governments’ (COAG) inprinciple commitment to remove retail price caps, roll out interval meters nationally and introduce more cost reflective pricing, progress has been slow. Without these core actions consumers cannot make the best choices about how they use electricity and manage spending, and third parties will be constrained in identifying investments in energy efficiency and demand management with the greatest benefits.

In the near term, the Authority supports additional action that will help increase the uptake of energy efficiency opportunities by consumers, suppliers and energy service companies. The Authority supports further exploration of the most effective mix of state and Commonwealth policies in the context of the Direct Action Plan.

Table D.5: Major barriers and potential solutions

Barriers to energy efficiency and demand management

Potential solutions

Lack of detailed information on electricity consumption

  • Consumers have a poor understanding of the relationship between electricity usage and costs and thus the potential benefits of reducing or altering their electricity use.
  • Lack of data on the time and location of electricity use makes it difficult for proponents of demand-side management to identify and communicate potential paybacks from specific demand-side investments.

Install interval meters to collect data on the location and time of use of electricity. To support their efficient deployment:

  • apply a minimum standard for smart meters; and
  • proceed with the rollout in defined situations, such as new connections or replacements.

Give consumers access to their load profile data, including to share with third parties. Amend the National Electricity Rules as suggested by AEMC (2012, p. 57) to make this process easy and timely.

Consider rule changes with the AEMC to publish additional electricity consumption data, at a greater level of detail. Undertake a cost-benefit analysis of a potential new market information role for AEMO in aggregating consumer data from electricity retailers and distributors, as considered by AEMC 2012.

Electricity prices are inflexible and do not reflect costs of supply

  • Most consumers do not pay electricity prices that accurately reflect the cost of supply at the time it is used; ‘average’ network pricing can encourage higher consumption at peak times and increase electricity bills over the long term. Also, pricing does not reflect costs of supplying electricity to a particular location. A variable network component in prices could better recover these network costs.

Deploy interval metering as a prerequisite to efficient network pricing.

Accelerate assessments of retail competition, as agreed by the Council of Australian Governments (COAG), to allow the removal of retail price caps where effective retail competition exists (Standing Council on Energy and Resources 2012). (This has already occurred in Victoria and South Australia.)

Adopt critical peak pricing, as recommended by the PC 2013 (p. 335). Phase in flexible and efficient pricing more broadly with a variable distribution network component, and allow consumers to opt in to cost-reflective tariffs as recommended by the AEMC (2012)(Productivity Commission 2013, p. 427).

Split or perverse incentives for investing in energy efficiency or demand management

  • The benefits to saving energy are not fully captured by any one party, so building owners, consumers, electricity retailers and distributors do not have sufficient motivation to invest in energy efficiency.
  •  

Regulatory reform to encourage distribution businesses to invest in demand-side options currently includes:

  • the 1 January 2013 introduction of the Regulatory Investment Test (RITD) that requires distribution businesses to consider and assess all credible demand-side options (above a $5 million threshold) before choosing the best investment option to meet their network’s needs;
  • the introduction of Standing Council on Energy and Resources-agreed recommendations arising from the AEMC’s December 2012 Power of Choice of Review, specifically around incentives for distribution businesses to undertake demand management projects; and
  • introducing incentives for non-network and network solutions to be considered on a level field.

 

Sources: Barriers identified in AEMC 2012; Dunstan, Sharpe and Downes 2013; Garnaut 2008; Productivity Commission 2005 and 2013; Prime Minister’s Task Group on Energy Efficiency 2010

In addition, the Authority supports initiatives that have been identified in previous reviews, including:

  • completing retail competition reviews and removal of retail price regulation where effective retail competition exists;
  • the Australian Energy Regulator implementing standard regulatory arrangements for interval meters;
  • proceeding with the rollout of interval meters for new connections and replacements;
  • collecting and publishing more detailed electricity consumption data, where it is deemed there are positive net benefits for consumers; and
  • accelerating the response time of the AEMC to rule change requests arising from independent reviews, including the SCER and Productivity Commission.

D3.6 Challenges to tracking progress in the electricity sector

The Authority considers that the best common measure of electricity activity is generation ‘as sent out’, but historical data (to 1990) is not available on this basis in a disaggregated, rigorous form. In order to compare historical and projected activity data, the Authority has used electricity generation ‘as generated’.

Information gaps also make it difficult to track progress in off-grid electricity generation. Off-grid electricity accounts for about 6 per cent of Australia’s electricity generation, and is mainly consumed by the mining and manufacturing sectors (ABS 2012). The level and mix of off-grid generation is a source of uncertainty because granular data is not collected routinely or systematically.

BREE’s inaugural report (2013d) on regional and remote electricity is a helpful source of new information. BREE ‘intends to report on the demand and supply of electricity in offgrid Australia on a regular basis) (2013d, p. 40). The Authority endorses this plan. Detailed reporting of off-grid generation will inform policy, planning and private investment. It could also help anticipate the potential implications of a shift from gas, which is currently the dominant fuel, and identify opportunities to deploy lower emissions generation over time (ABS 2012; ACIL Allen Consulting 2013).

D3.7 Electricity sector summary

Electricity generation is the largest sectoral source of Australia’s emissions. Even with the RET operating as currently legislated, electricity sector emissions are projected to grow strongly unless additional incentives or policies are in place.

There are significant emissions reduction opportunities and their take-up can be driven by a price incentive. Modelling suggests that about half of the least-cost changes in emissions to reach Australia’s minus 5 per cent target, if only domestic emissions reductions were used, could be found in the electricity sector. Strong incentives would drive a larger sectoral emissions reduction.

Emissions reductions will come both from reducing electricity demand and from improving the emissions intensity of electricity supply. Both are important. To at least 2020, there is likely to be little new investment in grid-connected electricity generation and in the next few years there is only limited scope to reduce emissions by changing the emissions intensity of supply, unless it is driven by policy (including the RET). Emissions reductions, in addition to those identified in modelling, could be delivered by removing non-price barriers to industrial, commercial and residential energy efficiency.

Appendix D4 Transport

D4.1 Transport emissions overview

Transport greenhouse gas emissions are produced by vehicles combusting fuels to move people and freight. Australia’s transport emissions are reported across four modes – road, rail, domestic aviation and domestic shipping. International aviation and shipping emissions are excluded from Australia’s national inventory. Emissions associated with producing and refining liquid and gaseous fuels, as well as generating electricity, are attributed to stationary energy and fugitives sectors.

Figure D.18: Transport emissions share of australian emissions, 1990–2030

Figure D.18 shows the historical and projected share of transport emissions between 1990 and 2030.Transport emissions increase from 62 megatonnes of carbon dioxide equivalent in 1990 to 91 megatonnes of carbon dioxide equivalent in 2012. In 2020, transport emissions are projected to be 99 megatonnes of carbon dioxide equivalent in the no price scenario, 96 megatonnes of carbon dioxide equivalent in the low scenario, 94 megatonnes of carbon dioxide equivalent in the medium scenario and 92 megatonnes of carbon dioxide equivalent in the high scenario. In 2030, transport emissions are projected to be 106 megatonnes of carbon dioxide equivalent in the no price scenario, 99 megatonnes of carbon dioxide equivalent in the low scenario, 91 megatonnes of carbon dioxide equivalent in the medium scenario and 83 megatonnes of carbon dioxide equivalent in the high scenario.

Source: Climate Change Authority calculations using results from The Treasury and DIICCSRTE 2013

Figure D.19: Passenger road transport activity and emissions intensity – modelled range, 1990–2050

Figure D.19 shows historical and projected passenger road transport activity and emissions intensity between 1990 and 2050. Between 1990 and 2012 passenger road transport activity increased from 123 to 175 billion vehicle kilometres travelled and this is projected to increase to around 290 billion vehicle kilometres travelled in 2050. Between 1990 and 2012 the emissions intensity of passenger road transport decreased from 287 to 255 grams of carbon dioxide equivalent per vehicle kilometre travelled and this is projected to decrease to between 107 and 157 grams of carbon dioxide equivalent per vehicle kilometre travelled in 2050.

Note: Upper and lower line bounds illustrate range of modelled outcomes.
Source: Climate Change Authority calculations using results from The Treasury and DIICCSRTE 2013 and CSIRO 2013

Figure D.20: Passenger road transport activity and fuel intensity – four scenarios, 1990–2050

Figure D.20 shows historical and projected passenger road transport activity and emissions intensity across four scenarios between 1990 and 2050. Between 1990 and 2012 activity increased and emissions intensity decreased over the same period. Activity is projected to continue increasing to 2050 across all scenarios while emissions intensity is projected to continue falling across all scenarios over the same period.

Source: Climate Change Authority calculations using results from The Treasury and DIICCSRTE 2013 and CSIRO 2013

Transport accounted for 91 Mt CO2-e (15 per cent) of Australia’s emissions in 2012. Under the medium scenario, transport is projected to account for a similar proportion of total emissions in 2020, reducing to 14 per cent in 2030, as shown in Figure D.18.

Australia’s per capita transport emissions are higher than those of most other countries (IEA 2012, p. 102). Australia’s urban form, low population density and long intercity distances mean we are heavily reliant on road transport and domestic aviation. To the extent that these factors are fixed, most of the Australian population and business will continue to depend on these transport modes.

In all scenarios modelled by The Treasury and DIICCSRTE (2013), considerable growth in road and aviation activity is projected, balanced by reduced emissions intensity in scenarios where carbon price incentives play an increasing role. Passenger road transport activity is expected to increase substantially from about 179 billion to 290 billion vehicle kilometres between now and 2050 (Figure D.19).

Under scenarios with a price incentive, the emissions intensity of passenger road transport is projected to decline significantly between now and 2030, and eventually stabilise between 2040 and 2050, as shown in Figure D.20.

Beyond 2035, however, emissions intensity improvements are not expected to offset growth in the transport task, resulting in growing transport emissions. Continuing growth in activity is estimated to drive up transport emissions to between 98 and 128 Mt CO2-e in 2050, as presented in Figure D.21. This is higher in all scenarios than the 2000 level of 75 Mt CO2-e.

D4.2 Transport emissions outcomes, contributors and drivers

Figure D.21: Transport emissions outcomes and contributors, 1990–2050

Figure D.21 shows the historical and projected contributors to Australia’s transport emissions between 1990 and 2050. From 1990 to 2012, transport emissions increased from 62 to 91 megatonnes of carbon dioxide equivalent. Transport emissions are projected to be between 98 and 128 megatonnes of carbon dioxide equivalent in 2050. Between 1990 and 2012 cars contributed between around 50 to 60 per cent of Australia’s transport emissions. This contribution is projected to be around 45 per cent in 2020 and 2030 and between 30 to 36 per cent in 2050. Relative to 2000, changes in road passenger and freight demand were the main contributors to Australia’s lower emissions in 1990 and increased emissions in 2012. Increased road passenger and freight demand are projected to be the main contributors to Australia’s transport emissions across all scenarios to 2050. At the same time increased road passenger vehicle efficiency is projected to make the largest net negative contribution to transport emissions across all scenarios.

Source: Climate Change Authority calculations using results from The Treasury and DIICCSRTE 2013 and CSIRO 2013

Demand for transport is driven by population growth, economic activity and costs associated with travel (DCCEE 2012, p. 25).

Road transport accounted for 77 Mt CO2-e (84 per cent) of all transport emissions in 2012. It includes light vehicles (motorcycles, cars and light commercial vehicles) and heavy vehicles (rigid and articulated trucks and buses). Light vehicles accounted for 57 Mt CO2-e (63 per cent) of total transport emissions. Passenger vehicles account for most of the transport task and, as a consequence, are the largest contributor to emissions, as represented in Figure D.21. Australia’s per capita light vehicle ownership and use is stabilising, making population growth a dominant driver for future growth in passenger road transport.

Road freight is the second largest contributor to emissions, and includes a diverse range of activities such as bulk freight hauled by large articulated trucks, transport of goods between retail and distribution centres, and point-to-point courier movements. The road freight task is growing quickly – between 2000–01 and 2008–09, Australia’s road freight task grew by 37 per cent, from 139 billion tonne-kilometres to 191 billion tonne-kilometres (BITRE 2012, p. 47), driven by increased wealth and economic activity.

Domestic aviation activity, dominated by passenger transport, increased by 80 per cent between 2000–01 and 2010–11 (BITRE 2012, p. 89) and is projected to double by 2050 (DCCEE 2012, p. 15). This strong growth in domestic aviation has been largely driven by broader economic growth and increasing passenger preference for air travel over road or rail. Air travel has become more affordable – real airfares have not changed considerably in the last decade (and declined in the case of discount fares), while real median and average incomes have increased (BITRE 2013 and PC 2013, p. 60). Domestic aviation accounts for more than half of non-road transport emissions (8 Mt CO2-e) and emissions from rail and domestic shipping each account for about 3 Mt CO2-e.

In The Treasury and DIICCSRTE (2013) modelling, price incentives apply to only a minority of transport emissions, including those from heavy onroad vehicles from 2014–15. Incentives for light vehicle emissions reduction are not modelled. Emissions from light vehicles are, however, influenced by the incentives applied to other subsectors, which may lead to spillovers of technology improvements and use of lower emissions fuels.

The largest modelled contributors to emissions reduction in transport relate to road passenger and road freight transport, including vehicle efficiency improvements, vehicle electrification and the uptake of low emissions fuels including biofuels. These are reflected in Figure D.21.

Vehicle emissions intensity, expressed in grams of CO2 per kilometre (g CO2/km), serves as a robust proxy for vehicle efficiency across fuel types. The emissions intensity of new light road vehicles sold in Australia has improved by 21 per cent from 252 g CO2/km in 2002 to 199 g CO2/km in 2012 (NTC 2012, p. 5). This has been driven by technology advances and consumer preferences. Continued improvement is projected to reduce the transport emissions intensity of new vehicles to 2050 in all scenarios. CSIRO modelling included a sensitivity analysis, which showed light vehicle CO2 standards3 could offer 4.7 Mt CO2-e emissions reduction per annum in 2030 and 5.6 Mt CO2-e per annum in 2050, relative to the case in which those standards were not implemented.

The broad adoption of lower emission fuels, notably sustainable biofuels, could reduce transport emissions. Under the low and high scenarios, respectively, biofuels are projected to provide 10 to 20 per cent of Australia’s road transport fuel needs by 2030, resulting in an emissions reduction of between 2 Mt CO2-e and 8 Mt CO2-e per annum compared to the no price scenario.

The projected uptake of electric road vehicles, already underway but expected primarily after 2020, also contributes to the reduction of transport emissions. The emissions attributable to electric vehicles will depend on the source of the electricity. Therefore, net emissions reduction from vehicle electrification depend on the emissions intensity of the electricity supply (Garnaut 2008, p. 519). In 2050, electric road vehicles are projected to deliver a transport sector emissions reduction of between 2 Mt CO2-e and 6 Mt CO2-e per annum under the low and high scenarios, respectively, compared to a no price scenario.

D4.3 Progress in transport emissions reduction

The highest emissions reduction potential could come from improvements in road vehicle efficiency and electrification, switching to alternative fuels and shifting to alternative transport modes. These options are discussed below, with an emphasis on the emissions reduction opportunities.

D4.3.1 Road vehicle efficiency

Light vehicle efficiency improvements (including fleet-average downsizing) could offer approximately 18 Mt CO2-e to 19 Mt CO2-e of emissions reductions per annum by 2050 (Graham et al. 2012b, pp. 40–42). Light vehicle efficiency improvements are expected under a business as usual (BAU) setting, with consumer preferences influenced by price incentives such as fuel prices. Improvements can also be significantly increased by regulations on vehicle carbon dioxide emissions.

Despite recent improvements, Australia lags behind other major economies in light vehicle fuel efficiency and CO2 emissions. There has been widespread international adoption of standards on vehicle fuel efficiency and CO2 emissions. Regulations and targets intended to significantly improve on BAU outcomes are in place or being established in major markets such as the EU, the United States, Canada, China, Japan and South Korea.

Mandatory CO2 emissions standards are considered one of the most cost-effective strategies to reduce transport emissions (DIT 2011, p. 3). Aside from emissions reduction benefits, any cost to consumers of vehicle emissions standards, such as increased average vehicle price, is largely, if not completely, offset by the fuel savings rewarded over the life of the vehicle. The overall cost to society of emissions standards, at levels comparable to international action, is estimated to be negative (that is, it delivers net savings) even after upfront costs are taken into account.

ClimateWorks Australia (2010, p. 78) suggests that, in Australia to 2020, a standard of 140 g CO2/km could deliver societal savings of up to $74 per tonne of CO2 avoided, and could achieve annual emissions reductions of 5.5 Mt CO2 with benefits to the economy of about $400 million. The potential savings increase to $85 per tonne of CO2 for a standard of 120 g CO2/km, which could deliver emissions reductions of 6.3 Mt CO2 with economic benefits of about $535 million.

Australia does not necessarily receive the full benefit of international fuel efficiency standards, despite the fact that about 85 per cent of light vehicles sold in Australia today are imported (DIT 2011). The most fuel-efficient vehicles and model variants are typically allocated to markets with mandatory standards (DIT 2011, p. 8).

At 198 g CO2/km, on average, light passenger vehicles sold in Australia in 2011 were 46 per cent more emissions-intensive than those sold in the same year in the EU, which averaged 136 g CO2/km (NTC 2012, p. 24). The EU has a number of policies to reduce CO2 emissions from new vehicles, including a fleet-average target of 95 g CO2/km for new light passenger vehicles by 2020 (European Commission 2012). Australia regulates light vehicle air toxic emissions using the New European Drive Cycle (NEDC) applied in the EU, making comparisons robust. Drive cycle tests are conducted in other major markets including Japan and the United States; however, the NEDC differs by using simulation testing while the other two use real-world in-use data (IEA 2013, p. 4).

If Australia pursued a similar relative improvement in its fleet-average emissions as that implied by the EU 2020 target, new light passenger vehicles sold in Australia in 2020 would be about 20 per cent more efficient than those sold today. Adopting a target comparable to the EU (95 g CO2/km by 2020) could reduce emissions intensity of new light passenger vehicles, on average, to around half of today’s level.

In its 2011 Discussion Paper, the then Department of Infrastructure and Transport presented a range of potential standards for discussion (DIT 2011, p. 14). The least stringent scenario (190 g CO2/km by 2015 and 155 g CO2/km by 2024) would see Australia adopting targets considerably less ambitious than other major economies, while the more ambitious scenarios in the discussion paper set Australia on an emissions reduction path comparable with the United States by 2020 (see Figure D.22).

Figure D.22: Comparison of light vehicle CO2 emission rate projections, 2000–2025

Figure D.22 shows a historical and projected comparison of light vehicle carbon dioxide emission rates between 2000 and 2025. In 2020, Australia’s light vehicle carbon dioxide emissions are projected to be 153 grams of carbon dioxide equivalent per kilometre travelled, the highest of the countries referenced. The lowest is the EU at 95 grams of carbon dioxide equivalent per kilometre travelled.

Note: The illustrated target for Australia of 153g CO2/km by 2020 does not reflect (and overstates) the least stringent scenario (of 155g CO2/km by 2024) presented in the 2011 Department of Infrastructure and Transport Discussion Paper (DIT 2011, p. 14).
Source: Adapted from Façanha et al. 2012, p. 8

There are fewer technical improvements available that could have a large impact on heavy vehicle emissions. Projections suggest that, compared to current practice, there is a potential to reduce emissions through efficiency by up to 5 Mt CO2-e in 2050 (Graham et al. 2012b, p. 45). Adoption of low-rolling resistance tyres and regenerative braking systems may offer another 2 Mt CO2-e of cost-effective emissions reductions in 2050 (Graham et al. 2012b, p. 46).

Given the long lifetimes of ships, locomotives and aircraft, there are also fewer opportunities to improve energy efficiency through stock turnover of these vehicles. The largest emissions reduction opportunities for non-road vehicles, compared to current practice, are through technology advances such as engine efficiency and vessel weight, which could reduce transport emissions by about 7 Mt CO2-e in 2050 (Graham et al. 2012b, pp. 49, 52 and 54).

By way of comparison, domestic aviation and shipping emissions were about 8 Mt CO2-e and 3 Mt CO2-e, respectively, in 2012.

D4.3.2 Vehicle electrification

Vehicle electrification, combined with a decarbonised electricity sector, offers substantial emissions reduction potential. Vehicles need not be fully electric – there are various degrees of electrification which allow a progressively higher proportion of travel to be covered electrically, such as in stand-alone hybrid electric vehicles (HEVs) and plug-in hybrid electric vehicles (PHEVs).

The emissions of purely electric vehicles (EVs) and PHEVs – when operating in full electric mode – are represented in the electricity sector rather than transport. Their fuel cycle emissions intensity compared to internal combustion engine vehicles (ICEVs) and HEVs depends on the emissions intensity of the electricity grid and relative vehicle efficiencies. Typical mass-produced EVs are more than twice as energy efficient as ICEVs.

With a low-emissions electricity supply, the electrification of light and heavy vehicles could offer emissions reductions of between 23 Mt CO2-e and 25 Mt CO2-e in 2050 (Graham et al. 2012b, pp. 40 and 47). One of the current barriers to the take up of EVs is their high up-front cost compared with ICEVs and HEVs (although operating costs are much lower). Given assumed technology improvements and cost reductions, the cost of owning an EV could reach parity with the cost of owning an ICEV by the late 2020s, as indicated in Figure D23.

Figure D.23: Projected emissions reduction cost of electric vehicles, 2010–2050

Figure D.23 shows the projected emissions reduction cost of electric vehicles between 2010 and 2050. In 2010, this cost was around $70 per tonne of carbon dioxide equivalent and this is projected to reach parity ($0 per tonne of carbon dioxide equivalent) with internal combustion engine vehicles around the late 2020s before reaching a negative cost of almost $10 per tonne of carbon dioxide equivalent around the late 2030s and staying there to 2050.

Source: Graham et al. 2012a, p. 25

D4.3.3 Fuels and energy

Alternative transport fuels are both available and in development, including shale oil, coal-to-liquid, gas-to-liquid, gaseous fuels and biofuels. Some modelled scenarios project a significant increase in biofuel use; however, there is a risk that future oil prices or supply constraints could prompt Australia to exploit fuels that have higher lifecycle emissions to meet its transport fuel needs. Improving vehicle efficiency and electrification of transport mitigates this risk.

With a price incentive, the adoption of biofuels for road transport could reduce annual emissions by up to 3 Mt CO2-e in 2050. Increased biofuel use could diminish the potential for emissions reductions from vehicle electrification, and vice versa.

For rail and domestic shipping, the use of biofuels could offer the largest emissions reduction opportunity, totalling 2 Mt CO2-e to 4 Mt CO2-e in 2050 (Graham et al. 2012b, pp. 53 and 55). This is also the case for domestic aviation, where biofuels have the potential to reduce emissions in aviation by 6 Mt CO2-e in 2050 (Graham et al. 2012b, p. 50).

The emissions reduction potential of biofuels depends on the availability of appropriate feedstock. There are generally two kinds of biofuels in production or development. First-generation or conventional biofuels are produced from grain-based feedstocks. Second-generation biofuels (including Australian biofuels) are produced from waste materials and co-products of food production, and reduce the potential for food displacement or other unsustainable environmental outcomes. Current supply of feedstock in Australia is not expected to be enough to meet substantial increases in demand (Wild 2011), and other potential sources may be favoured to supply a growing market for biofuels.

The degree to which road vehicles adopt biofuels (including ethanol and biodiesel) will depend on manufacturer decisions based on oil prices and consumer preferences in response. Flex-fuel vehicles capable of operating on high ethanol content petrol blends, as well as unleaded petrol, are relatively common in the United States, but only a very small number of models in Australia are compatible with ethanol/petrol blends greater than 10 per cent ethanol by volume. Regulatory drivers, such as New South Wales’s biofuel mandates (New South Wales Government 2013), can also increase biofuel use. Such mandates are directed at ethanol blends of 10 per cent or less, which do not require flex-fuel capability.

Natural gas may gain significant share of the transport fuels mix; however, it is likely to depend on the relative pricing of natural gas to alternatives such as biofuels and conventional diesel.

Liquefied petroleum gas is not projected to gain significant future additional market share for road vehicles or locomotives; however, future prices of alternatives may change this outlook.

D4.3.4 Mode shift

There is potential for emissions reductions through mode shifts from road freight to rail and shipping. Based on international research, rail and shipping offer lower emissions intensity transport, at an average of 23 g CO2 per tonne-km and 513 g CO2 per tonne-km, respectively. By comparison, road freight averages 120 g CO2 per tonne-km (Cristea et al. 2011, p. 38). Coupled with improved logistics, mode shift could offer an opportunity to reduce freight emissions by up to 5 Mt CO2-e per annum in 2050 (Graham et al. 2012b, p. 82).

Passenger mode shift from private vehicles to public and active transport could also offer emissions reduction opportunities, with options ranging from additional public transport infrastructure to measures that encourage cycling and walking. It is estimated that switching from private car to other transport modes could offer emissions reductions of up to 7 Mt CO2-e per annum by 2050 (Graham et al. 2012b, pp. 69, 70 and 72).

Australia’s cities are more sparsely populated than most cities of the world (DIT 2013, p. 112), and this presents a barrier to broader use of public and active transport. The potential for passenger mode shift is difficult to quantify – users’ mode selection depends on the alternative transport options available and, potentially, associated travel behaviour change programs.

Appendix D5 Direct combustion

Figure D.24: Direct combustion share of Australian emissions, 1990–2030

Figure D.24 shows the historical and projected share of direct combustion emissions between 1990 and 2030. Direct combustion emissions increase from 66 megatonnes of carbon dioxide equivalent in 1990 to 95 megatonnes of carbon dioxide equivalent in 2012. In 2020, direct combustion emissions are projected to be 119 megatonnes of carbon dioxide equivalent in the no price scenario, 118 megatonnes of carbon dioxide equivalent in the low scenario, 116 megatonnes of carbon dioxide equivalent in the medium scenario and 112 megatonnes of carbon dioxide equivalent in the high scenario. In 2030, direct combustion emissions are projected to be 134 megatonnes of carbon dioxide equivalent in the no price scenario, 126 megatonnes of carbon dioxide equivalent in the low scenario, 125 megatonnes of carbon dioxide equivalent in the medium scenario and 118 megatonnes of carbon dioxide equivalent in the high scenario.

Source: Climate Change Authority calculations using results from The Treasury and DIICCSRTE 2013

D5.1 Direct combustion emissions oveview

Direct combustion is burning fuels for stationary energy purposes, such as generating heat, steam or pressure. Direct combustion excludes fuels combusted for electricity generation.

Australia’s direct combustion emissions were 13 per cent and 16 per cent of total Australian emissions in 2000 and 2012, respectively.

The oil and gas industries, metal manufacturing and households are large contributors to direct combustion emissions. The balance of emissions can be attributed to other industry and commercial use.

Australia’s rapidly expanding liquefied natural gas (LNG) industry is expected to be the main contributor to direct combustion emissions, particularly in the next few years. By 2020, direct combustion emissions are projected to be about 49 to 59 per cent higher than 2000 levels. By 2030, direct combustion emissions are projected to be about 57 to 79 per cent higher than 2000 levels (Figure D.24).

From 2012 to 2030, direct combustion is projected to be responsible for the largest absolute increase in emissions in any sector of the Australian economy – driven primarily by LNG production – except under the no price scenario.

Emissions from direct combustion are closely correlated with the total energy content of fuel combusted. Direct combustion emissions intensity improved moderately between 2000 and 2012, and this is projected to continue across all scenarios to 2030 (figures D.25 and D.26), due to natural gas taking an increasing share of the total primary energy mix.

Figure D.25: Direct combustion activity and emissions intensity, 1990–2030

Figure D.25 shows historical and projected direct combustion activity and emissions intensity between 1990 and 2030. Between 1990 and 2012 direct combustion activity increased from 849 to 1 412 gigajoules and this is projected to increase to around 1867 to 2122 gigajoules in 2030. Between 1990 and 2012 direct combustion emissions intensity decreased from 77 to 67 kilograms of carbon dioxide equivalent per gigajoule and this is projected to decrease to around 63 kilograms of carbon dioxide equivalent per gigajoule in 2030.

Note: Upper and lower line bounds illustrate range of modelled outcomes
Source: Climate Change Authority calculations using results from The Treasury and DIICCSRTE 2013

Figure D.26: Historical and projected direct combustion activity and emissions intensity, 1990–2030

Figure D.26 shows historical and projected direct combustion activity and emissions intensity across four scenarios between 1990 and 2030. Between 1990 and 2012 activity increased and emissions intensity decreased. Activity is projected to continue increasing to 2030 across all scenarios while emissions intensity is projected to continue falling across all scenarios over the same period.

Source: Climate Change Authority calculations using results from The Treasury and DIICCSRTE 2013

D5.2 Direct combustion emissions outcomes, contributors and drivers

Figure D.27 shows the impact of The Treasury and DIICCSRTE modelling (2013) on direct combustion emissions in each modelled scenario. All scenarios show a strong increase in emissions to 2020, with the lowest projected direct combustion emissions in 2020 almost 50 per cent higher than 2000 levels. The opportunity for emissions reduction, regardless of the level of incentive, is somewhat limited by long-term supply contracts in the growing LNG industry.

Direct combustion emissions from LNG production relate to onsite use of natural gas to fuel stationary equipment, particularly the compression turbines used to liquefy natural gas. BREE (2013) projected demand for Australia’s energy resources will accelerate, with LNG net exports growing by 156 per cent between 2000 and 2011, and projected to grow by 405 per cent between 2011 and 2020. BREE (2011 and 2012a) projected growth in LNG exports to continue past 2020 before stabilising after 2030.

Figure D.27: Direct combustion emissions and contributors, 1990–2030

Figure D.27 shows the historical and projected contributors to Australia’s direct combustion emissions between 1990 and 2030. From 1990 to 2012, direct combustion emissions increased from 66 to 95 megatonnes of carbon dioxide equivalent. Direct combustion emissions are projected to be between 118 and 134 megatonnes of carbon dioxide equivalent in 2030. Between 1990 and 2012, gas direct combustion emissions contributed around 40 to 50 per cent of total direct combustion emissions. This contribution is projected to be around 58 per cent in 2020 and a similar amount in 2030. Relative to 2000, changes in gas direct combustion emissions were the main contributor to Australia’s lower emissions in 1990 and increased emissions in 2012. Gas direct combustion emissions are projected to be the main contributor to Australia’s direct combustion emissions across all scenarios to 2030. At the same time decreased use of ‘other fuels’ is projected to make the largest net negative contribution to direct combustion emissions across all scenarios.

Source: Climate Change Authority calculations using results from The Treasury and DIICCSRTE 2013

Table D.6: Selection of Australian LNG projects over 5 million tonnes per year production capacity in operation, under construction or planned

LNG projects in operation

Start date

Total capacity (tonnes/year)

North West Shelf

In operation

16.3 million

LNG projects in construction

Start date

Total capacity (tonnes/year)

Queensland Curtis (Qld)

2014

8.5 million

Gorgon Trains 13 (WA)

2015

15 million

Gladstone (Qld)

2015

7.8 million

Wheatstone/Julimar (WA)

2016

8.9 million

Ichthys (NT)

2017

8.4 million

LNG projects planned

Start date

Total capacity (tonnes/year)

Browse (WA)

2017

12 million

Pluto 2 & 3 (WA)

Unknown

8.6 million

Gorgon Trains 45 (WA)

Unknown

10 million

Wheatstone Trains 35 (WA)

Unknown

13.4 million

Australia Pacific LNG Trains 24 (Qld)

Unknown

13.5 million

Queensland Curtis Trains 34 (Qld)

Unknown

7.8 million

Note: Does not total Australia-wide; smaller projects are not listed
Source: BREE 2012b

A significant proportion of the projected LNG industry emissions can be considered locked in – there is over 153 million tonnes of annual LNG production capacity in operation, under construction or planned in Australia (BREE 2012b) (Table D.6). In comparison, LNG exports totalled 19 million tonnes in 2011 (BREE 2012).

More generally across the industrial, residential and commercial sectors, energy efficiency is likely to play an increasingly important role across all forms of direct combustion, somewhat constraining growth in emissions.

D5.3 Progress in direct combustion emissions reduction

D5.3.1 Natural gas industry

The projected increase in direct combustion emissions results from large increases in LNG exports and limited opportunities to improve the emissions intensity of LNG production. Demand for Australian fossil fuel exports such as LNG is driven by commodity prices and the exchange rate, as well as global and regional economic growth.

Improvements in emissions intensity may come from energy efficiency gains in turbines and other machinery. Australia Pacific LNG (2010) notes that the most fuel-efficient turbines result in approximately 25 per cent less greenhouse gas emissions compared with commonly used turbines around the world. Additionally, heat captured from a gas turbine’s exhaust may be used in the LNG liquefaction process to augment gas-fired boilers.

D5.3.2 Bauxite and alumina processing

Non-ferrous metal manufacturing, principally alumina production, is the second largest source of direct combustion emissions. As alumina is consumed in the aluminium manufacturing process, these two industries are linked, although alumina is also exported. BREE (2013) projects alumina exports to increase at an average annual rate of 0.9 per cent between 2012–13 and 2017–18, due to increased alumina production in excess of domestic consumption.

D5.3.3 Residential sector

Continued regulatory improvements for the thermal efficiency of residential homes and the energy efficiency of household appliances, such as hot water systems, could represent significant emissions reduction opportunities. George Wilkenfeld and Associates (2009) project that equipment energy efficiency standards affecting residential gas use may save 4.5 Mt CO2e between 2000 and 2020. This may be outweighed, however, by a projected increase in emissions from residential use of gas water heaters as conventional electric-resistive water heaters are phased out. The net emissions result will depend on householders’ preferences for gas, solar or heat-pump water heaters and choices between gas or electric heat-pump space heating.

Appendix D6 Fugitive emissions

Figure D.28: Fugitive emissions share of Australian emissions, 1990–2030

Figure D.28 shows the historical and projected share of fugitive emissions between 1990 and 2030.Fugitive emissions increase from 37 to 48 megatonnes of carbon dioxide equivalent between 1990 and 2012. In 2020, fugitive emissions are projected to be 79 megatonnes of carbon dioxide equivalent in the no price scenario, 71 megatonnes of carbon dioxide equivalent in the low scenario, 66 megatonnes of carbon dioxide equivalent in the medium scenario and 59 megatonnes of carbon dioxide equivalent in the high scenario. In 2030, fugitive emissions are projected to be 100 megatonnes of carbon dioxide equivalent in the no price scenario, 69 megatonnes of carbon dioxide equivalent in the low scenario, 67 megatonnes of carbon dioxide equivalent in the medium scenario and 50 megatonnes of carbon dioxide equivalent in the high scenario.

Source: Climate Change Authority calculations using results from The Treasury and DIICCSRTE 2013

D6.1 Fugitive emissions overview

Fugitive emissions are greenhouse gases emitted during the extraction, production, processing, storage, transmission and distribution of fossil fuels such as coal, oil and gas. Fugitive emissions do not include emissions from fuel combustion.

Australia’s fugitive emissions were 41 Mt CO2-e in 2000 and increased to 48 Mt CO2e in 2012. This represented 7 per cent and 8 per cent of Australia’s total emissions in 2000 and 2012, respectively.

Almost three-quarters of 2012 fugitive emissions were from the coal industry, with the balance from the oil and gas industry.

The Treasury and DIICCSRTE modelling (2013) projected fugitive emissions will increase relative to 2000 levels by 2030 under all scenarios. This ranges from a minimum projected increase of 8 Mt CO2-e to a maximum of 59 Mt CO2-e under the high and the no price scenarios, respectively (Figure D.28).

The projected increase in emissions from continuing growth in coal and LNG production is driven by strong global demand for Australia’s energy resources. The scenarios project a wide range of possible future fugitive emissions levels in 2030 (Figure D.29).

Figure D.29: Historical and projected fugitive emissions, 1990–2030

Figure D.29 shows historical and projected fugitive emissions between 1990 and 2030 across the coal, oil and gas, gas supply and refineries sub-sectors. Between 1990 and 2012 fugitive emissions increased in the coal and oil and gas sub-sectors, but remained relatively steady in the others. In 2030, coal fugitive emissions are projected to increase to around 30 to 70 megatonnes of carbon dioxide equivalent, oil and gas fugitive emissions to around 13 to 25 megatonnes of carbon dioxide equivalent and gas supply fugitive emissions to around 4 to 8 megatonnes of carbon dioxide equivalent. Fugitive emissions from refineries are projected to be below 1 megatonne of carbon dioxide equivalent in 2030.

Note: Upper and lower line bounds illustrate range of modelled outcomes.
Source: Climate Change Authority calculations using results from The Treasury and DIICCSRTE 2013.

D6.2 Fugitive emissions outcomes, contributors and drivers

Figure D.30 shows the projected fugitive emissions outcomes for each modelled scenario. All scenarios project a steep increase in emissions to 2020, with the lowest projected fugitive emissions in 2020 more than 40 per cent higher than 2000 levels. In 2030, fugitive emissions in the low and medium scenarios remain relatively steady compared to 2020 levels, whereas the no price scenario shows a large increase and the high scenario a noticeable decrease. This reflects the importance of strong incentives, which enhance the economic attractiveness of emerging emissions reduction processes, such as the oxidisation of ventilation air methane in coal mining.

Future fugitive emissions are projected to be driven by increased coal and gas production in response to increased global energy demand.

D6.2.1 Coal industry

Fugitive emissions in the coal industry depend on the level of coal production and the greenhouse gas content of the coal seams being mined. ClimateWorks Australia (2013) notes that some of the more emissions-intensive mines generate up to 0.8 t CO2-e of fugitive emissions per tonne of coal produced.

Underground mines are typically more emissions-intensive than surface mines because deeper coal seams are subject to greater pressures, which prevents the natural escape of emissions through cracks and fissures (Ecofys 2009 and US EPA 2006). Underground black coal mines contributed 19 per cent to Australian coal production in 2010–11 but 62 per cent of coal fugitive emissions (DCCEE 2012).

Australia’s fugitive emissions from coal will continue to be driven by international demand for Australian coal. For example, BREE (2013) projects total black coal production to increase from 11 700 PJ in 2012–13 to 18 000 PJ in 2049–50, and domestic black coal consumption to decrease from 1 200 PJ to 478 PJ.

Figure D.30: Fugitive emissions outcomes and contributors, 1990–2030

Figure D.30 shows the historical and projected contributors to Australia’s fugitive emissions between 1990 and 2030. From 1990 to 2012, fugitive emissions increased from 37 to 48 megatonnes of carbon dioxide equivalent. Fugitive emissions are projected to be between 50 and 100 megatonnes of carbon dioxide equivalent in 2030. Between 1990 and 2012, coal fugitive emissions contributed around 60 to 70 per cent of total fugitive emissions. This contribution is projected to be around 70 per cent in 2020 and around 66 per cent in 2030. Relative to 2000, changes in coal fugitive emissions were the main contributor to Australia’s lower fugitive emissions in 1990 and higher emissions in 2012. Fugitive emissions from coal are projected to be the main contributor to Australia’s fugitive emissions across all scenarios to 2030.

Source: Climate Change Authority calculations using results from The Treasury and DIICCSRTE 2013

D6.2.2 Oil and gas industry

Fugitive emissions in the gas industry include gas venting, gas flaring and losses associated with the transmission and distribution of gas. Between 2000 and 2012, fugitive emissions from natural gas venting and flaring decreased 18 per cent (The Treasury and DIICCSRTE 2013). Fugitive emissions from natural gas transmission and distribution increased by 55 per cent over this period (The Treasury and DIICCSRTE 2013). ClimateWorks Australia (2013) analysis suggests that the emissions intensity of natural gas transmission and distribution in 2010–11 was slightly less than in 2002–03, despite absolute emissions increases.

There was a 62 per cent increase in natural gas production between 2000 and 2011 (BREE 2013). Oil production decreased over this period; however, its relatively small contribution to emissions means it is not driving overall emissions reduction.

The Grattan Institute (2013) identifies a number of trends, including:

  • economic growth in China, India and the Middle East, leading to increased energy demand generally;
  • several countries changing their policies on nuclear power, notably Australia’s major trading partner Japan, following the Fukushima nuclear incident, leading to increased demand for alternative energy sources; and
  • climate change concerns making gas-fired power plants more attractive, as they emit less greenhouse gases than coal-fired power plants and are usually cheaper than renewable energy sources.

These factors combine to drive large increases in Australian gas production, which is projected to increase by about 184 per cent between 2012–13 and 2049–50 (BREE 2012). This is driven by a 316 per cent increase in projected net exports of LNG over the same period (BREE 2012). In comparison, domestic gas consumption over this period is projected to increase by 59 per cent.

D6.3 Progress in fugitive emissions reduction

D6.3.1 Coal industry

There are a number of emission reduction technologies which could be used by the coal industry, although there is uncertainty regarding the timing of their implementation. The United States Environmental Protection Agency (US EPA) (2006) identified three main fugitive emissions reduction measures for the coal industry – degasification to capture methane; enhanced degasification to capture low-grade methane and purify it; and oxidisation of ventilation air methane (when methane in a mine’s ventilation air is oxidised to generate heat or produce electricity).

ClimateWorks Australia (2013) identifies a ventilation air methane oxidisation cost of $17/t CO2-e. This suggests the implementation of ventilation air methane oxidisation will likely require a price incentive.

D6.3.2 Oil and gas industry

The US EPA (2006) identifies three main fugitive emissions reduction measures for the natural gas industry – equipment changes and upgrades, changes in operational practices, and direct inspection and maintenance.

Equipment changes and upgrades include pneumatic control devices which contain pressurised natural gas to operate valves and control pressure, flow or liquid levels (US EPA 2006a). Emissions reduction options include using pneumatic devices, which bleed less natural gas into the atmosphere, and replacing the pressurised natural gas with compressed air (Copenhagen Consensus on Climate 2009).

Changes in operational practices includes preventing the venting of methane before pipeline maintenance or repairs. This may mean recompressing the gas during maintenance and repairs or using surge vessels, which clears the pipeline of methane for short periods (Ecofys 2009).

Direct inspection and maintenance refers to the identification and rectification of leaks across the natural gas transmission and distribution network. Infrared cameras can be used to identify methane emissions and, if coupled with emissions measurement technologies such as pressure sensors, allow leaks to be tracked and rectified more efficiently than would otherwise be the case (Clean Air Task Force 2009).

There is uncertainty around the emissions from coal seam gas (CSG) extraction. The reserves of CSG in Australia are substantial, with deposits concentrated in Queensland and New South Wales. BREE (2012b) estimates that CSG comprises about 29 per cent of Australia’s gas resources.

The level of CSG fugitive emissions in the future, however, is unclear as there has been limited direct measurement (Hardisty et al. 2012). CSG fugitive emissions are currently estimated by applying an emissions factor applicable to conventional gas (ClimateWorks 2013). Citing estimates of fugitive emissions from CSG devised by Hardisty et al. (2012) and Howarth et al. (2011), the Climate Institute (2012) finds that in 2020, committed and probable LNG projects could result in fugitive emissions from CSG production of 1223 Mt CO2-e. In comparison, fugitive emissions from natural gas venting and flaring, and transmission and distribution totalled 13 Mt CO2-e in 2012 (The Treasury and DIICCSRTE 2013).

Appendix D7 Industrial processes

Figure D.31: Industrial process emissions share of Australia’s emissions, 1990–2030

Figure D.31 shows the historical and projected share of industrial process emissions between 1990 and 2030. Industrial process emissions increased from 26 to 32 megatonnes of carbon dioxide equivalent between 1990 and 2012. In 2020, industrial process emissions are projected to be 37 megatonnes of carbon dioxide equivalent in the no price scenario, 32 megatonnes of carbon dioxide equivalent in the low scenario, 27 megatonnes of carbon dioxide equivalent in the medium scenario and 21 megatonnes of carbon dioxide equivalent in the high scenario. In 2030, industrial process emissions are projected to be 45 megatonnes of carbon dioxide equivalent in the no price scenario, 24 megatonnes of carbon dioxide equivalent in the low scenario, 22 megatonnes of carbon dioxide equivalent in the medium scenario and 11 megatonnes of carbon dioxide equivalent in the high scenario.

Source: Climate Change Authority calculations using results from The Treasury and DIICCSRTE 2013

D7.1 Industrial process emissions overview

The main sources of industrial process emissions are metal production in iron and steel and aluminium products; synthetic greenhouse gases from refrigeration and airconditioning use; chemical processes in fertiliser and explosives manufacturing; and mineral production, primarily in the cement industry. Industrial process emissions exclude energy-related emissions such as the burning of fossil fuels for heat, steam or pressure.

Australia’s industrial process emissions accounted for about 32 Mt CO2-e, or (5 per cent) of Australia’s emissions in 2012.

From 1990 to 2012, industrial process emissions increased by almost 7 Mt CO2-e due to increased use of synthetic greenhouse gases and growing chemical production, partly offset by lower metal production and improved metal processing (Figure D.31).

In 2012, industrial process emissions were composed of metal production (37 per cent), synthetic greenhouse gases (27 per cent), chemical processing (19 per cent), mineral production (15 per cent) and other production (2 per cent).

The Treasury and DIICCSRTE modelling projects industrial process emissions to be lower, relative to 2000 levels, by 2 to 4 Mt CO2-e in 2030 under the low and medium scenarios, respectively, and about 15 Mt CO2-e (59 per cent) under the high scenario. In the high scenario, emissions are reduced through improved chemical processing and the transition to alternative refrigerant gases.

Figure D.32: Process emissions from metal production, synthetic greenhouse gases and other production, 1990–2030

Figure D.32 shows historical and projected industrial process emissions between 1990 and 2030 from the metal production, synthetic greenhouse gases and other production sub-sectors. Between 1990 and 2012, metal production emissions declined from around 15 to 12 megatonnes of carbon dioxide equivalent while synthetic emissions increased from around 1 to 9 megatonnes of carbon dioxide equivalent over the same period. Other production emissions remained unchanged at less than 1 megatonne of carbon dioxide equivalent over the same period. In 2030, metal production emissions are projected to be 4 to 12 megatonnes of carbon dioxide equivalent, synthetic greenhouse gases emissions around 2 to 13 megatonnes of carbon dioxide equivalent and other production reaching 1 megatonne of carbon dioxide equivalent in 2030.

Note: Upper and lower line bounds illustrate range of modelled outcomes.
Source: Climate Change Authority calculations using results from The Treasury and DIICCSRTE 2013

Figure D.33: Process emissions from chemical production and mineral production, 1990–2030

Figure D.33 shows historical and projected industrial process emissions between 1990 and 2030 from the chemical processing and minerals production sub-sectors. Between 1990 and 2012, chemical processing emissions increased from around 2 to 6 megatonnes of carbon dioxide equivalent while minerals production emissions decreased from 6 to 5 megatonnes of carbon dioxide equivalent over the same period. In 2030, chemicals emissions are projected to be 3 to 14 megatonnes of carbon dioxide equivalent, while minerals emissions are projected to be 1 to 6 megatonnes of carbon dioxide equivalent in 2030.

Note: Upper and lower line bounds illustrate range of modelled outcomes
Source: Climate Change Authority calculations using results from The Treasury and DIICCSRTE 2013

Figure D.34: Industrial process emissions and contributors, 1990–2030

Figure D.34 shows the historical and projected contributors to Australia’s industrial process emissions between 1990 and 2030. Industrial process emissions remained unchanged at 26 megatonnes of carbon dioxide equivalent from 1990 to 2000, before rising to 32 megatonnes of carbon dioxide equivalent in 2012. The increase in emissions was attributed to increases in emissions from both the chemical processing and synthetic greenhouse gas sectors which was partly offset by decreased metal and mineral production emissions. In 2030, industrial process emissions are projected to decrease by up to 15 megatonnes of carbon dioxide equivalent, relative to 2000 emissions, under the low, medium and high scenarios. The main emission reductions are projected to come from the metal production and mineral processing sectors and will offset the increase in emissions from the chemical and synthetic greenhouse gas sectors. Under the no price scenario, emissions are projected to increase by 19 megatonnes of carbon dioxide equivalent due to an increase in emissions from the chemical processing and synthetic greenhouse gas sector, compared with 2000 level emissions.

Source: Climate Change Authority calculations using results from The Treasury and DIICCSRTE 2013

D7.2 Industrial process emissions outcomes, contributors and drivers

The majority of the projected emissions reduction in 2030 results from installing nitrous oxide conversion catalysts (nitric acid manufacturing) and replacing ozone-depleting substances and refrigerants with lower emitting alternatives.

The historical decrease in metal production emissions relates to reduced iron and steel production and improved metal processing. In particular, aluminium emissions intensity fell by over 60 per cent between 1990 and 2011 due to reductions in perfluorocarbon (PFC) emissions intensity (DIICCSRTE 2013). Various industry sources suggest the recent reductions in PFC emissions intensity are not expected to continue (ClimateWorks 2013). Metal production has contracted recently, as a result of the closure of one of Bluescope Steel’s Port Kembla steelworks in 2011 and Norsk Hydro’s Kurri Kurri aluminium operations in 2012.

According to The Treasury and DIICCSRTE (2013), synthetic greenhouse gas emissions (used as propellants and refrigerants) are projected to reduce from current levels by about 2 Mt CO2-e in 2020 under the medium scenario and 4 Mt CO2-e under the high scenario.

Chemical sector emissions are expected to increase in line with both ammonia and nitric acid production to make ammonium nitrate, which is the key ingredient for explosives and fertilisers. Projects are planned to increase ammonium nitrate production capacity by over 1 300 kilotonnes per annum by 2020 (ClimateWorks 2013). The resulting upwards pressure on nitric acid emissions will largely be offset by the installation of nitrous oxide conversion catalysts and ClimateWorks (2013) estimated this technology could reduce greenhouse gas emissions by 44 per cent in 2020, even with the expected increase in production.

 

Mineral production emissions largely result from the cement industry. ClimateWorks (2013) reported that cement emissions intensity reduced by 11 per cent between 2002 and 2012, and has the potential to decrease by a further 6 per cent by 2020, from increasing substitution of supplementary materials in clinker production. It is expected the recent announcements by industry to import greater volumes of clinker, replacing domestic production, will limit the expansion of domestic cement production and emissions (Adelaide Brighton 2013; The Treasury and DIICCSRTE 2013).

D7.3 Progress in industrial process emissions reduction

D7.3.1 Metal production

Aluminium, iron and steel production accounts for the majority of emissions in the metal sector, and there is a level of uncertainty surrounding future production levels. BREE (2012, 2013) projects iron and steel production will continue to decline in the short term, while ClimateWorks (2013) estimates production will stabilise following the closure of Port Kembla in 2011. No new metal projects are expected in the near term.

There are only two major producers of iron and steel in Australia – Arrium and Bluescope Steel. The closure of one of Bluescope Steel’s two blast furnaces at its Port Kembla plant in 2011 reduced its annual steel-making production by about 2.6 million tonnes and its crude steel production by almost 30 per cent in 2011–12 (Bluescope 2013; Climateworks 2013). This was due to the ‘record high Australian dollar, low steel prices and high raw material costs’, compounded by weak steel demand (Bluescope 2011, p. 5). Bluescope added that ‘The decision is a direct response to the economic factors affecting the business and is not related to the Federal Government’s proposed carbon tax’ (Bluescope 2011, p. 5). Similar factors, including overcapacity in the aluminium industry, led to the closure of the Kurri Kurri plant in 2012 (Norsk Hydro 2012).

Weaker domestic construction activity and the high Australian dollar, combined with the weak international steel market, are expected to continue to supress metal production to 2014. In the medium to long term, these factors are expected to improve (Arrium 2013).

ClimateWorks (2013) projected that the emissions intensity of metal production will remain stable to 2020, as the industry is characterised by mature technologies with high capital intensity and long investment cycles. At present, there are ‘no near to midterm technology improvements that will deliver large step reductions in carbon steelmaking emissions’ (Arrium 2011, p. 24). Carbon capture and storage technology requires significant capital expenditure and offers large emissions reduction potential. Pilot projects are currently operating in Japan and Korea (IEA 2013).

Further, ClimateWorks (2013) reported minimal reductions in aluminium emissions intensity given the near removal of perfluorocarbon (PFC) emissions since 1990. For example, only 20 grams of PFC were emitted per tonne of aluminium produced in 2011, compared with over 450 grams in 1990 (DIICCSRTE 2013).

D7.3.2 Synthetic greenhouse gases

Ozone-depleting greenhouse gases, such as chlorofluorocarbons (CFCs) and hydrochlorofluorocarbons (HCFCs), are referred to as synthetic greenhouse gases. They are not recorded in Australia’s National Greenhouse Gas Inventory (NGGI). These gases are, instead, managed through the Montreal Protocol, an international environmental protection agreement which sets out binding obligations for the progressive phasing out of ozone-depleting substances.

Australia’s NGGI does not capture the environmental and climate benefits delivered from replacing ozone-depleting gases with alternative synthetic greenhouse gases, such as hydrofluorocarbons (HFCs). HFCs are covered by the Kyoto Protocol. As a result, the substitution from ozone-depleting gases to HFCs has increased industrial process emissions reported in the NGGI. Between 2000 and 2012, the increase in industrial process emissions from synthetic greenhouse gases was about 7 Mt CO2-e. Overall, despite the increase in reportable emissions, the transition to HFCs has contributed to a net climate benefit (DCCEE 2012).

Refrigerants Reclaim Australia (RRA) has administered an industry-funded program that collected, reclaimed and destroyed waste and unwanted refrigerants and ozone-depleting substances. RRA reported it had recovered about 4 445 tonnes of refrigerant gases between July 1993 and June 2012, avoiding emissions of about 10 Mt CO2-e (including non-Kyoto gases). Projected rates of recovery of refrigerant gases are expected to reach over 900 tonnes per year by 2020, approximately doubling present recovery rates (RRA 2013).

While the Treasury and DIICCSRTE modelling projects a reduction in synthetic greenhouse gas emissions of up to 6 Mt CO2-e in 2020 depending on the level of the price incentive, there are alternative views. For example, ClimateWorks (2013) projects that reportable synthetic greenhouse gas emissions could be about 4 Mt CO2-e higher in 2020 if recent trends continue, largely due to the progressive replacement of ozone-depleting substances with HFCs.

D7.3.3 Chemical processes

Widespread adoption of nitrous oxide conversion catalysts in nitric acid production is projected by 2020 and is currently being trialled in Australia (ClimateWorks 2013). In March 2012, Orica (2009, 2012) completed trials and implemented this technology in four of its Australian plants, with estimated emissions reductions of at least 65 per cent. Wesfarmers (2013) reported an emissions reduction of up to 85 per cent from ongoing trials.

Incitec Pivot Limited (2012) installed nitrous oxide conversion catalysts at its newly constructed Moranbah Plant, which has capacity to produce over 300 kilotonnes per annum.

State-based environmental guidelines for nitric acid plants are also helping to reduce emissions in this sector.

Chemical process emissions from the production of ammonia, synthetic rutile and titanium dioxide will be considered for analysis in the Final Report.

D7.3.4 Mineral production

Over half of the emissions associated with cement manufacturing are attributed to clinker production (Cement Industry Federation of Australia 2013). Progress is being made to reduce emissions and increase production through greater use of supplementary materials such as flyash, slag and cement extenders. Since 2003, industry use of these materials increased by 68 per cent and reached over 3 million tonnes in 2012 (ClimateWorks 2013, CIF 2012).

Adelaide Brighton (2012) reported it had increased its clinker substitution to almost 16 per cent in 2012, avoiding nearly 0.5 Mt CO2-e of emissions by using waste materials that would otherwise be placed in landfill. Boral is also increasing its clinker substitution through proprietary technology to reduce the emissions intensity of concrete by over 40 per cent (ClimateWorks 2013).

Adelaide Brighton (2013) recently announced that it intends to import all its clinker from 2015 onwards. Similarly, Boral (2013) has increased its clinker imports to almost 30 per cent after the closure of its Waurn factory in 2012.

Appendix D8 Agriculture

Figure D.35: Agriculture emissions share of Australian emissions, 1990–2030

Figure D.35 shows the historical and projected share of agriculture emissions between 1990 and 2030. Agriculture emissions increase from 99 to 100 megatonnes of carbon dioxide equivalent between 1990 and 2012. In 2020, agriculture emissions are projected to be 102 megatonnes of carbon dioxide equivalent in the no price scenario, 100 megatonnes of carbon dioxide equivalent in the low scenario, 95 megatonnes of carbon dioxide equivalent in the medium scenario and 92 megatonnes of carbon dioxide equivalent in the high scenario. In 2030, agriculture emissions are projected to be 122 megatonnes of carbon dioxide equivalent in the no price scenario, 114 megatonnes of carbon dioxide equivalent in the low scenario, 113 megatonnes of carbon dioxide equivalent in the medium scenario and 109 megatonnes of carbon dioxide equivalent in the high scenario.

Source: Climate Change Authority calculations using results from The Treasury and DIICCSRTE 2013

D8.1 Agriculture emissions overview

Agricultural emissions are those from livestock digestive processes (enteric fermentation), manure management, nitrous oxide emissions from cropping and pastureland soils, prescribed burning of savannas and burning of agricultural residues. Combustion of fossil fuels in farming and cropping activities is covered under other sectors. Activities that change carbon sequestration in agricultural soils are covered under land use, land use change and forestry (LULUCF), discussed in Appendix D9.

Agriculture accounted for 17 per cent of total Australian emissions in 2012. This share is projected to remain relatively stable until 2030 under the medium scenario. Agriculture emissions are relatively insensitive to a price signal compared to the rest of the economy; total emissions are projected to be 42 per cent lower under the high scenario compared to the no price scenario in 2030, but are only projected to drop by 5 per cent between the high and no price scenarios in 2030.

From 1990 to 2012, agriculture emissions increased from 99 Mt CO2-e to 100 Mt CO2-e. The Treasury and DIICCSRTE modelling projects that agriculture emissions will be 18 Mt CO2-e higher in 2030 under the medium scenario, and 23 Mt CO2-e higher under the no price scenario.

About three-quarters of agriculture emissions were from livestock in 2012; the remainder were shared relatively evenly between cropping and savanna burning.

Enteric emissions from beef and dairy cattle are the dominant single source of emissions in the sector, making up over half of total agriculture emissions in 2012.

Livestock emissions are primarily methane, whereas emissions from cropping activities are primarily nitrous oxide from applying fertilisers, dung, manure and crop residues to soils.

Figure D.36: Agriculture emissions, 1990–2050

Figure D.36 shows historical and projected agriculture emissions between 1990 and 2050. In 1990, 2000 and 2012, agriculture emissions were around 100, 105 and 100 megatonnes of carbon dioxide equivalent respectively. In 2050, agriculture emissions are expected to be 30 per cent above 2000 levels in the high scenario, 32 per cent above 2000 levels in the medium and low scenarios and 37 per cent above 2000 levels in the no price scenario.

Source: Climate Change Authority calculations using results from The Treasury and DIICCSRTE 2013

D8.2 Agriculture emissions outcomes, contributors and drivers

Figure D.37 sets out actual agriculture emissions by subsector from 1990 to 2030 for each of the scenarios modelled by The Treasury and DIICCSRTE. It also sets out the contribution of different subsectors to changes in agriculture sector emissions from 2000 levels.

Agriculture sector emissions are projected to be relatively stable from 2012 to 2020, and then increase substantially to 2030 under all scenarios.

From 2020, livestock activities are the major source of projected increases in emissions, with cropping activities the next largest source. Savanna burning contributes a small reduction in emissions from 2020 to 2030.

The Treasury and DIICCSRTE modelling (2013) projects that, after remaining relatively stable from 2013 to 2020, agriculture emissions will grow substantially under all scenarios, to 102–106 Mt CO2-e in 2020 and 117–123 Mt CO2-e in 2030.

Most of the projected increases in emissions from 2020 to 2030 are attributable to livestock under the medium scenario. CIE (2013) projects that beef cattle numbers will grow substantially from 2020–2030.

Dairy cattle emissions are a smaller source of emissions at about 8 Mt CO2-e or 8 per cent of total agriculture emissions in 2012. The Treasury and DIICCSRTE modelling projects that emissions will remain relatively stable at about 8 Mt CO2-e in 2020, but decrease slightly in relative terms to about 7 per cent of agriculture emissions in 2020 and 2030.

As noted above, agriculture emissions are projected to be relatively insensitive to the level of a price signal. This is likely to be the result of a combination of factors, which could include relatively high costs and limited solutions for emissions reduction in the agriculture sector, projected strong export demand for agriculture commodities in the medium to long term, and that the modelled scenarios did not apply a mandatory carbon price to the agriculture sector, but instead a voluntary price incentive under the Carbon Farming Initiative (CFI).

D8.2.1 Contributors

The main contributors to emissions in the agriculture sector are livestock numbers and the amount of crop production, as reflected in the rate of fertiliser application. Changes in practices and the technologies that reduce emissions from livestock and crops are also contributors, but are expected to have a lesser influence on emissions.

D8.2.2 Drivers

The primary drivers of emissions from the agriculture sector are agricultural commodity prices and weather conditions. These factors are in evidence in the recent agricultural emissions trends and projections set out in Figure D.37. Drought was the dominant factor in the fall in agricultural emissions between 2000 and 2008.

Figure D.37: Agriculture emissions outcomes and contributors, 1990–2050

Figure D.37 shows the historical and projected contributors to Australia’s agriculture emissions between 1990 and 2030. Between 1990 and 2012, agriculture emissions stayed around 100 megatonnes of carbon dioxide equivalent. Agriculture emissions are projected to be 117 to 123 megatonnes of carbon dioxide equivalent in 2030. In 1990 and 2012, livestock emissions contributed 84 and 73 per cent, respectively, to total agriculture emissions. This contribution is expected to be around 76 per cent in 2020 and 78 per cent in 2030. In 1990, increased emissions from livestock and reduced emissions from savannah burning and cropping were the main contributors to the change in agriculture emissions relative to 2000. In 2012, increased emissions from savannah burning and decreased emissions from livestock were the main contributors to the change in agriculture emissions relative to 2000. In 2020, reduced emissions from livestock are projected to be the largest net negative contributor to agriculture emissions in all scenarios except the no price scenario. In 2030, increased livestock emissions are projected to be the largest contributor to agriculture emissions in all scenarios.

Note: ‘Other factors’ includes adjustments due to the broader economic effects of the carbon price. The effect is less than one per cent of emissions.
Source: Climate Change Authority calculations using results from The Treasury and DIICCSRTE 2013

Improved weather conditions and export demand are expected to drive emissions growth in the short to medium term. Prices for agricultural commodities have stabilised at historically high levels in recent years following a peak in 2010 (derived from Reserve Bank of Australia 2013). Australian beef and veal exports are expected to increase in the period from 2012 to 2018, reflecting increased demand from the United States and some smaller emerging markets (ABARES 2013a, p. 88), although beef livestock numbers are expected to decline gradually over this period. Prices for major cropping outputs (grains and oilseeds) are projected to remain above their historical average to 2018 (ABARES 2013a, p. 42). Demand for dairy commodities is also expected to grow over this period (ABARES 2013a, p. 119). Over the longer term, sustained growth in export demand from emerging economies is projected to continue driving growth in livestock and cropping production and the associated emissions (Linehan et al. 2012, p. 1).

The CFI provides a price-based incentive for agricultural emissions reduction and is the main source of projected emissions reduction under the low, medium and high scenarios relative to the no price scenario. The effects of the CFI on absolute emissions levels are projected to be relatively small compared to the macroeconomic drivers for farm production discussed above. Estimating emissions reductions from the CFI is difficult, however, as it relies, among other things, on assumptions about the development and uptake of technology and the future rules of the CFI.

D8.2.3 Agriculture emissions reduction potential

The Treasury and DIICCSRTE modelling projects that under the medium scenario, agriculture emissions would be approximately 3 Mt CO2-e lower than in the no price scenario in 2020 and 5 Mt CO2-e lower in 2030, and approximately 3 Mt CO2-e and 6 Mt CO2-e lower under the high scenario. This constitutes a relatively small reduction in the trend of growing agricultural emissions in the projections. Most of this reduction would come from livestock.

Separate analysis by ClimateWorks finds less emissions reduction is likely from livestock in 2020; it estimates 0.3 Mt CO2-e of emissions reduction, attributable to methane capture and destruction from manure at piggeries (ClimateWorks 2013a, p. 36). In contrast, The Treasury and DIICCSRTE modelling assumes that some additional sources of methane emissions reduction from livestock would also be available and in use in 2020. These could include herd management, animal feed supplementation, feedlot finishing and pasture improvements.

Australian Bureau of Agricultural and Resource Economics and Sciences (ABARES) analysis suggests greater potential for emissions reduction at the carbon prices modelled for 2020. ABARES cost curves (Figure D.38) suggest that about 7 Mt CO2-e of project-based emissions reduction from livestock is available at the price incentive used in the high scenario in 2020, relative to business as usual.

It is important to note that there are significant differences in the assumptions and purposes of each of these studies that affect their results, including the set of technologies considered, the uptake of viable emissions reduction technologies, and whether only private or also public costs are considered.

D8.3 Progress in agriculture emissions reduction

Additional analysis of contributors and drivers for emissions reduction is set out below.

D8.3.1 Export demand

In the longer term, increased demand for agricultural commodities in emerging Asian economies is projected to be a strong driver of agricultural production and emissions. ABARES projects that demand for agrifood commodities will double between 2007 and 2050 in Asia, and increase by 48 per cent in the rest of the world (Linehan et al. 2012, p. 1). Increased wealth and changes in diets in emerging economies are expected to drive the greatest increases in demand for high-value agriculture products such as vegetables and fruit, meat, dairy products, cereals and fish. Australia is likely to be in a good position to meet increased demand from Asian economies due to its proximity to these export markets and comparative advantages in producing several high-value agricultural products. ABARES projects that Australia’s production of agrifood products will increase by 77 per cent from 2007 to 2050 (Linehan et al. 2012, p. 11).

D8.3.2 Carbon Farming Initiative drivers and barriers

The primary driver of emissions reduction from the CFI is the revenue project providers receive. This is illustrated by the ABARES cost curves for livestock methane emissions reduction (Figure D.38). ABARES estimates that large dairy farms may start to adopt anti-methanogenic vaccines at a price as low as $35 per tonne, with sheep farms not finding this practice economic until a price of $175 per tonne (ABARES 2013, p. 26). This technology is still in the early stage of development.

Potential project providers will make an assessment of the future value of emissions units when assessing the financial viability of projects. Uncertainties in economic forecasts and in the future policy environment could have substantial effects on the estimated price of emission units and the assessed viability of CFI projects, particularly for projects that have a long payback period.

Figure D.38: Marginal cost of livestock methane emissions reduction, 2020 and 2030

Figure D.38 shows the marginal cost of livestock methane emissions reductions in 2020 and 2030. In 2020, emissions reductions of around 1 to 5 megatonnes of carbon dioxide have a marginal cost of around $50 per tonne of carbon dioxide equivalent. In 2020, around 10 megatonnes of carbon dioxide equivalent of emissions reductions has a marginal cost of around $250 per tonne of carbon dioxide equivalent. In 2030, emissions reductions of around 1 to 6 megatonnes of carbon dioxide equivalent has a marginal cost of around $50 per tonne of carbon dioxide equivalent. In 2030, emissions reductions of around 12 megatonnes of carbon dioxide equivalent has a marginal cost of around $225 per tonne of carbon dioxide equivalent.

Source: ABARES 2013, p. 23

The availability of methodologies for CFI projects, and the ease of compliance with those methodologies, will be another important driver of uptake of emissions reductions. There are currently seven approved methodologies for agriculture emissions (four for destruction of methane from dairy and piggery manure, two for savanna burning and one for dietary additives to reduce emissions from dairy cows).

There are a range of other barriers to uptake of emissions reduction opportunities under the CFI, including limited access to capital, lack of scale economies on many farms, and difficulties with access to information about emissions reduction projects. These challenges may be exacerbated by the presence of many small and dispersed participants in the sector. There were about 135 000 farm businesses in Australia in 2010–11 (Australian Bureau of Statistics 2012), with 55 per cent reporting agricultural operations value of under $100 000. In this context, a trend toward increasing farm sizes in recent decades may act as another driver for emissions reduction. The share of total output from broadacre farms (including sheep, beef, mixed sheep–beef, grains and mixed livestock and crop industries) with production over $400 000 increased from 38 to 64 per cent from 1982–83 to 2002–03 (Productivity Commission 2005, p. 38).

A range of approaches could be taken to reduce barriers, such as ensuring ready access to information using existing rural information networks, simplifying methodologies for projects, facilitating access to capital and facilitating the use of project providers to consolidate projects across multiple small farms.

8.3.3 Production efficiency improvements

Although not explicitly incorporated in The Treasury and DIICCSRTE modelling, international research suggests that improvements in agricultural productivity can reduce emissions per unit of production (Tubiello et al. 2013, p. 91). Internationally, there has been a trend toward a slowing down of productivity improvements (Alston et al. 2009, p. 1209). To maintain productivity and emissions efficiency improvements to 2050 for Australian agriculture, continued investment in research and development is likely to be required (Carberry et al. 2010, pp. 7, 13).

Appendix D9 Land Use, Land Use Change and Forestry

Figure D.39: LULUCF share of Australian emissions, 1990–2030

Figure D.39 shows the historical and projected share of Australia’s land use, land use change and forestry sector (LULUCF) emissions between 1990 and 2030. LULUCF emissions were 140 megatonnes of carbon dioxide equivalent in 1990, 71 megatonnes of carbon dioxide equivalent in 2000 and 21 megatonnes of carbon dioxide equivalent in 2012. Emissions are projected to continue to decrease under all scenarios in 2020 and 2030, except the no price scenario where emissions are projected to increase to 34 megatonnes of carbon dioxide equivalent in 2030. Emissions are projected to decrease by 15 to 23 megatonnes of carbon dioxide equivalent in 2030.

Source: Climate Change Authority calculations using results from The Treasury and DIICCSRTE 2013

D9.1 LULUCF emissions overview

Land use, land use change and forestry (LULUCF)-related emissions and sequestration are caused by human-induced changes in forest cover since January 1990. Following changes to Kyoto Protocol rules for accounting for land sector emissions, since January 2013 LULUCF also includes net emissions from land and forest management activities. Emissions from LULUCF between 1990 and 2012 have been revised to be consistent with the new accounting rules. Combustion of fossil fuels from forestry activities, such as use of fossil fuels in logging machinery, is covered in other sectors.

LULUCF has been the biggest sectoral contributor to emissions reduction in Australia since 1990. Net emissions from the sector have declined by about 85 per cent from 140 Mt CO2-e in 1990 to 21 Mt CO2-e in 2012. The Treasury and DIICCSRTE modelling projects that, in the no price scenario, LULUCF emissions could increase to 30 Mt CO2-e in 2020 and 33 Mt CO2-e in 2030 (Figure D.39).

Land sector emissions are relatively sensitive to price incentives. Net emissions could be as low as 13 Mt CO2e in 2020 and 11 Mt CO2-e in 2030 under the high scenario.

Net LULUCF emissions are the result of substantial emissions and sequestration from biological systems – the 2012 net emissions of 21 Mt CO2-e are the result of about 47 Mt CO2-e emissions from deforestation, which were partially offset by sequestration from reforestation and afforestation.

Forestry is the dominant subsector for LULUCF. The Treasury and DIICCSRTE modelling projects that deforestation could result in emissions of over 50 Mt CO2-e in 2020 and 2030 under the no price scenario, amounting to almost all of the gross emissions from LULUCF. Forestry is also the major source of sequestration, through reforestation, afforestation and forest management.

Figure D.40: Net LULUCF emissions, 1990–2030

Figure D.40 shows Australia’s net land use, land use change and forestry sector (LULUCF) emissions under four scenarios from 1990 to 2030.LULUCF emissions decreased from 140 megatonnes of carbon dioxide equivalent in 1990 to around 70 megatonnes of carbon dioxide equivalent in 2000, and 20 megatonnes of carbon dioxide equivalent in 2012. Under all four scenarios, emissions are projected to remain well below 2000 emission levels. Under the no price scenario, net LULUCF emissions are projected to increase from 2012 onwards, reaching 34 megatonnes of carbon dioxide equivalent in 2030, 53 per cent lower than in 2000. Emissions are projected to decrease to 19 megatonnes of carbon dioxide equivalent in 2030 under both the low and medium scenarios, 73 per cent lower when compared with the 2000 emission levels. Under the high scenario, emissions are projected to further decrease to around 10 megatonnes of carbon dioxide equivalent in 2030, equivalent to 85 per cent lower when compared with the 2000 emission levels.

Source: Climate Change Authority calculations using results from The Treasury and DIICCSRTE 2013

Figure D.41: Deforestation and other land use change emissions and sequestration, 1990–2030

Figure D.41 shows the historical and projected emissions of deforestation and other land-use change sequestration. Deforestation emissions have fallen from around 140 megatonnes of carbon dioxide equivalent in 1990 to around 47 megatonnes of carbon dioxide equivalent in 2012. Deforestation emissions are projected to remain relatively stable between now and 2030. In 2030 deforestation emissions are projected to range between 42 and 52 megatonnes of carbon dioxide equivalent. Other land use change sequestration increased from zero in 1990 to 25 megatonnes of carbon dioxide equivalent in 2012. Other land use change sequestration is projected to range between 18 and 31 megatonnes of carbon dioxide equivalent in 2030.

Note: Negative emissions reflect carbon sequestration. Upper and lower line bounds illustrate range of modelled outcomes.
Source: Climate Change Authority calculations using results from The Treasury and DIICCSRTE 2013

D9.2 LULUCF emissions outcomes, contributors and drivers

Figure D.42 sets out actual LULUCF emissions and removals by subsector from 1990 to 2030, with net emissions from the sector shown by the orange circles, for each of the scenarios in The Treasury and DIICCSRTE modelling. The bottom chart sets out the contributions of different LULUCF activities to changes in net emissions from 2000 levels under each of the scenarios.

The vast majority of projected emissions and removals are from forestry activities (deforestation, reforestation and afforestation, and forest management). Non-forestry activities (cropland and grazing land management and revegetation) are much smaller sources of emissions and removals. Net LULUCF emissions increase from 2012 to 2030 under the no price scenario, but decrease under the other scenarios. Net emissions are relatively sensitive to a price incentive, with emissions under the high scenario less than one-third of emissions under the no price scenario in 2030. Among other things, this reflects relatively low-cost emissions reduction opportunities in the sector.

D9.2.1 Outcomes

Emissions from forestry are the result of clearing of land that was forest as at 1 January 1990, for use in another activity such as cropping or pasture (deforestation). Sequestration from forestry is the result of forests planted since 1990 removing carbon dioxide from the atmosphere (reforestation and afforestation), and sequestration from improved forest management practices for forests on land that was already planted in 1990 (forest management). Between 1990 and 2009, most land clearing occurred in New South Wales and Queensland.

The Treasury and DIICCSRTE modelling projects that under the medium scenario, net emissions from LULUCF could decrease by 3 Mt CO2-e from 2012 to 2020 and then remain relatively constant at around 18 to 21 Mt CO2-e through to 2030. Of this, forestry activities are projected to contribute almost all of the gross emissions from the sector in 2020 and 2030 and around 70 and 75 per cent of sequestration (from afforestation/reforestation and forest management) in 2020 and 2030. Under the high scenario emissions from LULUCF would be about 6 Mt CO2-e lower than the medium scenario in 2020 and 8 Mt CO2-e lower in 2030.

Figure D.42: LULUCF emissions and removals by activity, and contribution to change in emissions relative to 2000 levels, 1990–2030

Figure D.42 shows the historical and projected emissions and contributors to Australia’s land-use, land use change and forestry sector between 1990 and 2030. In 1990 land-use, land use change and forestry emissions were 140 megatonnes of carbon dioxide equivalent and fell to 21 megatonnes of carbon dioxide equivalent in 2012. By 2030 land-use, land use change and forestry emissions are projected to be 34 to 11 megatonnes of carbon dioxide equivalent. Between 1990 and 2012 deforestation fell from 140 to 47 megatonnes of carbon dioxide equivalent, the largest single contributor to land-use, land use change and forestry emissions over this period. Relative to 2000 level emissions, reductions in deforestation and an increase in forest management activities will account for the majority of emissions reductions between 2012 and 2030.

Source: Climate Change Authority calculations using results from The Treasury and DIICCSRTE 2013

From January 2013, Australia is required to count net emissions associated with forest management toward its emissions commitments under the Kyoto Protocol, and has also elected to include net emissions associated with cropland management, grazing land management and revegetation. The Treasury and DIICCSRTE modelling projects that there could be an emissions reduction from these practices, even in the absence of a price incentive, of about 15 Mt CO2-e in 2020 and about 13 Mt CO2-e in 2030. These emissions reductions are incorporated in the changes in net emissions from LULUCF discussed above. With a price incentive, emissions reduction from these activities could be much more substantial; under the medium scenario, emissions reductions from these activities are projected to be 21 Mt CO2-e in 2020 and 20 Mt CO2-e in 2030. Under the high scenario, reductions are projected to be about 26 Mt CO2-e in 2020 and 23 Mt CO2-e in 2030.

The historical emissions and sequestration from LULUCF to 2012, and projected emissions and sequestration to 2030 under the medium scenario, are set out in Figure D.43.

D9.2.2 Emissions reduction under the Carbon Farming Initiative

The CFI provides a price-based incentive for voluntary land-based emissions reduction projects. Current CFI methodologies for LULUCF projects cover environmental plantings, human-induced regeneration of native forests, native forest protection and reforestation.

Only certain types of plantation forestry activities are eligible for CFI projects. Regulations under the CFI contain a ‘positive list’ of activities that are eligible for the CFI (Carbon Credits (Carbon Farming Initiative) Regulations 2011). Other types of forestry and revegetation activities have been placed on the CFI ‘negative list’ and are directly excluded from the CFI. Negative list forestry activities include the establishment of forestry under Managed Investment Scheme (MIS) tax incentives under the Income Tax Assessment Act 1997, the cessation or avoidance of the harvest of a plantation, and the planting of a species in an area where it is known to be a weed. Both the positive and negative lists are likely to evolve over time.

D9.2.3 Contributors and drivers

The main contributors to emissions and emissions reduction in the LULUCF sector are the clearance of forested land for new purposes (deforestation), new forestry plantings on land that was unforested on 1 January 1990 (afforestation and reforestation), and the implementation of new practices that increase the amount of carbon sequestered in forests (forest management).

The main drivers of these contributors are agricultural commodity and input prices, forestry commodity and input prices, and state and Commonwealth land clearing rules. Other important drivers are the price that can be received for credits under the CFI, and improvements in land and forestry management practices outside of the CFI, carried out in response to regulatory requirements, to increase productivity or to achieve other environmental objectives.

Figure D.43: LULUCF emissions and sequestration (medium scenario), 1990–2030

Figure D.43 shows Australia’s emissions and sequestration from land use, land use change and forestry between 1990 and 2030 under the medium scenario. Deforestation has accounted for the majority of land use, land use change and forestry emissions since 1990 and is projected to continue to 2030. Between 1990 and 2012 these emissions have been in part offset by afforestation and reforestation activities. Between 2012 and 2030 vegetation and forest management sequestration activities will account for the majority of all sequestration activities.

Source: Climate Change Authority calculations using results from The Treasury and DIICCSRTE 2013

D9.3 Progress in land sector emissions reduction

As noted above, forests are the dominant source of emissions and emissions reduction in the LULUCF sector, with land clearing a major source of emissions.

Currently, most land cleared in Australia is used for cattle grazing, but in the past large areas of land have also been cleared for cropping (DCCEE 2013, p. 2). The value of agricultural products strongly influences decisions to clear additional forested areas, with a lag of about a year between moves in agricultural prices and land clearing activities. Figure D.44 demonstrates the relationship, with both the farmers’ terms of trade (being the ratio of an index of prices received by farmers to an index of prices paid by farmers) and the amount of land clearing decreasing over time.

Figure D.44: Land clearing and farmers’ terms of trade, 1973–2011

Figure D.44 shows Australia’s farmers’ terms of trade and hectares of land clearing between 1973 and 2011. The farmers’ terms of trade and the amount of land clearing have both fallen over the past three decades. Over this period the area of land cleared has reduced from around 600,000 hectares to less than 200,000 hectares.

Farmers’ terms of trade: ABARES: 2013a.
Source: Land clearing: DCCEE data used in the National Inventory Report 2011.

Land clearing, taxation and land use regulations in states and territories can influence expected returns or how easily land can be cleared or reforested. The Queensland land clearing regulations provide an example of the influence of policy. In 1989–90, Queensland had the highest LULUCF emissions of any state or territory in Australia, at 91 Mt CO2-e or 65 per cent of LULUCF emissions. New South Wales had the second highest emissions at 25 Mt CO2-e or 18 per cent of LULUCF emissions (DIICCSRTE 2013, p. 14). Restrictions on land clearance in Queensland were introduced in 2004 to first phase out and then ban most broadscale land clearing from 2007, and were strengthened in 2009. As a result, deforestation emissions in Queensland reduced significantly, from 34 Mt CO2-e in 2007–08 to 19 Mt CO2-e in 2010–11 (DIICCSRTE 2013, p. 21). New South Wales also introduced land clearing restrictions in 2005. Deforestation emissions from New South Wales fell from 25 Mt CO2-e in 1989–90 to 9 Mt CO2-e in 2010–11.

The effect of these rules on land clearing can be seen in Figure D.43, with a steep reduction in deforestation emissions from 2006 to 2011. The Queensland land clearing restrictions have recently been relaxed, with new legislation in 2013 returning aspects of Queensland’s land clearing framework to the conditions that applied prior to 2009. This is expected to put some upward pressure on emissions, although relatively stable projections for cattle numbers to 2020 suggest that this pressure will be limited in the short to medium term (Centre for International Economics 2013, p. 23). Australian net LULUCF emissions are projected to stabilise at about 20 Mt CO2-e per year under the medium scenario, for the period from 2012 to 2030.

The CFI provides an incentive structure to landowners or investors to undertake emissions reduction activity that is additional to other regulatory requirements. CFI forestry activities relate to avoided deforestation projects and the managed regrowth of deforested lands. The primary driver of emissions reduction activity from the CFI is the revenue that project providers receive for emissions reductions. This will affect rates of reforestation and afforestation, deforestation and forest management practices adopted. Projected emissions reductions from the CFI between 2012 and 2030 are outlined in Appendix C of The Treasury and DIICCSRTE modelling report.

Commodity prices for wood and wood products also influence decisions to invest in the forestry sector, which are balanced against the prices for competing agricultural uses and will be reflected in changed levels of afforestation and deforestation. Influences on commodity prices include structural timber demand; demand for paper; production of paper, paperboard, plantation woodchips and pulp in developing countries; and paper recycling.

Tax concessions for forestry have been a demand-side driver, with managed investment scheme (MIS) tax incentives affecting rates of afforestation, reforestation and deforestation, and contributing to plantation rates peaking in 2000 at 137 million hectares per year. Planting by these schemes fell sharply in response to the tightening of investment regulations in 2000 and 2007. In 2012, the area of plantation forests cleared exceeded new plantings, resulting in a reduction in the total plantation estate for the year (ClimateWorks 2013, p. 3).

A range of different policies has been used to reduce LULUCF emissions in different countries (see Box D.4).

Box D.4: International approaches to LULUCF

Other countries have adopted predominantly regulatory or a mix of regulatory and pricing approaches to preserve forests, with the measures used generally aimed at achieving a broad range of environmental and conservation objectives rather than primarily to limit emissions.

Brazil provides an example of a regulatory approach. In the early 2000s, deforestation accounted for about 75 per cent of Brazil’s total emissions. Through a package of command and control measures, new technology to monitor deforestation and targeted law enforcement actions, and in combination with prevailing lower agricultural prices, deforestation decreased by 82 per cent by 2011 (Climate Policy Initiative 2013).

New Zealand provides an example of a price-based approach to LULUCF, with forestry included in the New Zealand Emissions Trading Scheme (NZ ETS) from 1 January 2008. A projected 77 Mt CO2-e of removals were attributable to forestry over the Kyoto Protocol’s first commitment period (from 2008–2012), about 21 per cent of New Zealand’s total emissions (NZ Ministry for the Environment). Incentives under the NZ ETS are in addition to existing forestry rules that, among other things, limit the ability to harvest existing New Zealand native forests.

The Canadian province of Alberta has adopted an offsets project approach – the Alberta Offsets System – with some similarities to the Australian CFI offset credits may be earned by projects in a number of sectors, including LULUCF, and used by large-emitting facilities to meet obligations to reduce their emissions intensity. LULUCF activities that have approved protocols for projects include afforestation (although the protocol is currently under revision) and conservation cropping.

The US state of California also includes forestry projects in its compliance offsets program under the California Cap and Trade Program, which commenced enforceable compliance obligations in January 2013.

D9.3.1 Cost of land sector emissions reduction

The Australian National University (ANU) Centre for Climate Law and Policy submitted in response to the Issues Paper that substantial emissions reduction opportunities exist in the land sector that have been underestimated in Government modelling. It claimed that Australia could achieve about 110–115 Mt CO2-e of cumulative emissions reduction from the new land and forest management activities included in LULUCF from 2013–2020 with little or no policy effort (ANU Centre for Climate Law and Policy, Issues Paper submission, pp. 1314).

Analysis by ClimateWorks also suggests that there may be substantial emissions reduction available in the LULUCF sector at relatively low cost, with potential for, about 100 Mt CO2-e of annual emissions reduction identified for the LULUCF sector in 2020 at the price used for the medium scenario of around $30/t CO2-e (ClimateWorks Australia 2010, pp. 116, 127–131).

The opportunities identified by ClimateWorks include cropland management, tillage and residue management practices, and reduced deforestation. The ClimateWorks estimates also incorporate disaggregated emissions reduction from savanna burning, which are normally covered under the agriculture sector in Australia’s emissions inventory.

It is important to note that there may be significant differences in assumptions and purposes between The Treasury and DIICCSRTE modelling and the other estimates discussed above, including the set of technologies considered, the level of uptake of viable emissions reduction opportunities, and whether only private or also public costs are considered. The opportunities identified by the ANU Centre for Climate Law and Policy and ClimateWorks Australia are, nevertheless, significantly higher than are projected to be taken up in the sector by The Treasury and DIICCSRTE modelling, and warrant further investigation. There may be barriers to the uptake of emissions reduction opportunities that create significant differences between assessed emissions reduction potential and the level of uptake. These are discussed in more detail below, in the context of the CFI.

D9.3.2 Barriers to emissions reduction

The uptake of CFI emissions reduction projects by landowners or investors depends on the amount of revenue generated, and the level of risk landowners and investors are willing to accept, given the responsibilities associated with participation in the scheme. In the case of forestry or other projects that involve changing or locking in a particular land use, the revenues generated will need to be sufficient to offset the opportunity cost of alternative land uses.

Specific risks and uncertainties for the CFI include:

  • Relative agricultural commodity prices – High terms of trade for agricultural output may work against investing in CFI projects that involve forestry on potential agricultural land. Previous estimates of reforestation potential have indicated that landowners would typically only consider reforesting non-irrigated dryland, which has relatively low agricultural returns (Burns et al. 2011, p. 24).
  • Price of emission units – A volatile or uncertain market for emission units can act as a disincentive for landowners considering participating in CFI projects. Under the CFI, landowners and investors receive units for carbon sequestration projects as trees or soils sequester carbon from the atmosphere. Once the trees or soils have stored as much carbon as they can, the project ceases to receive returns, but landowners may continue to incur management costs (Burns et al. 2011, p. 13).
  • Permanency – CFI projects that sequester carbon are required to maintain that sequestration ‘permanently’ (for 100 years in the case of forestry projects), which may dampen the uptake of projects. Land value can be adversely affected due to limitations on its future use (ClimateWorks 2013, p. 44).
  • Capital constraints – Some projects will require significant upfront investment of capital prior to making returns. For instance, reforestation projects generally require significant capital upfront for land preparation and planting, but will make returns over an extended time period as the growing forest sequesters carbon.

Recent work by the CSIRO suggests that, depending on assumptions about factors such as the rate of carbon sequestration, the price of carbon and plantation establishment costs, over the longer term there may be an opportunity to establish very substantial new forestry plantings that could, for example, contribute 50–100 Mt CO2-e per year in emissions offsets (Polglase et al. 2011, p. 20). The Polglase et al. study modelled a number of assumptions, including carbon prices up to $50/t CO2-e, and also noted that gap payments may be necessary to encourage plantings on marginal land where biodiversity co-benefits may be greatest. It concluded that over the longer term there may be an opportunity to establish enough new plantings to help contribute to emissions reduction targets and derive other benefits. This research, if confirmed, suggests potential for substantial sequestration in response to a price incentive.

Appendix D10 Waste

Figure D.45: Proportion of Australian emissions, 1990–2030

Figure D.45 shows the historical and projected share of Australia’s waste emissions between 1990 and 2030. Waste emissions were 21 megatonnes of carbon dioxide equivalent in 1990, 17 megatonnes of carbon dioxide equivalent in 2000 and 15 megatonnes of carbon dioxide equivalent in 2012. Emissions are projected to continue to decrease under all scenarios in 2020 and 2030, except the no price scenario where emissions are projected to remain at 15 megatonnes of carbon dioxide equivalent in both 2020 and 2030. Emissions are projected to decrease by 2 to 4 megatonnes of carbon dioxide equivalent in 2020 and 6 to 8 megatonnes of carbon dioxide equivalent in 2030.

Source: Climate Change Authority calculations using results from The Treasury and DICCSRTE 2013

D10.1 Waste emissions overview

Waste includes solid waste and wastewater from residential, commercial and industrial activity. Waste emissions are primarily methane and nitrous oxide, which arise as organic waste decomposes in the absence of oxygen. Emissions from solid waste in landfill comprise about 80 per cent of the sector’s emissions, with wastewater accounting for about 20 per cent, and incineration and other sources for the remainder.

The waste sector is a relatively small contributor to Australia’s emissions, accounting for about 15 Mt CO2-e (3 per cent) of the national emissions total in 2012 (Figure D.45). The Treasury and DIICCSRTE modelling projects waste emissions could remain at about 1 per cent of total national emissions to 2030 under the medium scenario.

Waste sector emissions have decreased by about 8 per cent (just over 1 Mt CO2-e) since 2000, continuing the trend seen in sectoral emissions since 1990 (26 per cent decrease). This has been due to a range of policies and regulations that have driven the diversion of waste from landfill, and the uptake of emissions reduction technologies, including capturing emissions for electricity generation.

Since 2000, emissions intensity of wastewater has declined by about 14 per cent, while the emissions intensity of landfill has declined by about 8 per cent over the same period (Figure D.47). In 2008, there was a large increase in the diversion of waste, resulting in a large reduction in solid waste volumes sent to landfill.

Figure D.46: Solid waste emissions intensity, 1990–2030

Figure D.46 shows historical and projected solid waste activity and the emissions intensity of solid waste between 1990 and 2030. Between 1990 and 2012 activity rose from 16,425 kilotonnes to 19,805 kilotonnes and is projected to increase to 22,769 kilotonnes by 2030. Between 1990 and 2012 the emissions intensity of solid waste supply fell from 1.26 to 0.77 tonnes of carbon dioxide equivalent per tonne of solid waste. Solid waste emissions intensity is projected to be between 0.64 and 0.30 tonnes of carbon dioxide equivalent per tonne of solid waste by 2030.

Note: Upper and lower line bounds illustrate range of modelled outcomes
Source: Climate Change Authority calculations using results from The Treasury and DICCSRTE 2013

Figure D.47: Emissions intensity of landfill, 1990–2030

Figure D.47 shows historical and projected landfill activity and the emissions intensity of landfill across four scenarios between 1990 and 2030. Between 1990 and 2012 activity in kilotonnes of landfill deposited increased while the emissions intensity of waste declined by around 0.3 tonnes carbon dioxide equivalent per tonne of landfill. Activity is projected to continue increase to 2030 across all scenarios while the emissions intensity of landfill is projected to continue to fall to 2030 in all scenarios.

Source: Climate Change Authority calculations using results from The Treasury and DICCSRTE 2013

While total waste generated is expected to increase in the future, The Treasury and DIICCSRTE modelling shows that total waste emissions are expected to stabilise at about 15 Mt CO2-e by 2030 under a no price scenario. Under the modelled low and high scenarios, emissions are projected to fall even further to between 9 and 7 Mt CO2-e respectively (Figure D.46).

Emissions intensity of solid waste is projected to fall about 30 per cent from 2000 levels to 0.47 t CO2-e per tonne of waste under the no price scenario; whereas intensity is projected to fall to about 0.18 t CO2-e per tonne of waste under the high scenario (Figure D.47).

D10.2 Waste emissions outcomes, contributors and drivers

Since 1990, waste emissions have steadily fallen as a result of a range of local, state and national policies and schemes targeting the waste sector. These varied interventions have ranged from direct regulations such as local planning laws to market-based incentives including the Carbon Farming Initiative (CFI), the Greenhouse Gas Abatement Scheme (GGAS), the Renewable Energy Target (RET) and the carbon pricing mechanism. These interventions have driven the diffusion of emissions-reducing technologies to landfill waste and wastewater facilities, and also driven greater recycling, composting and other alternative waste treatments.

The main contributor to emissions from the waste sector is the volume of waste, which is driven by growth in population and economic activity. The main contributors to emissions reductions in the sector are the level of waste diverted for recycling or alternative waste treatments, and the extent to which the methane generated by decomposing waste is captured and destroyed. Figure D.48 shows the contribution of the two major waste streams to total waste emissions under the different modelled scenarios. Solid waste emissions comprise landfill emissions, incineration emissions and composting emissions; whereas wastewater emissions comprise industrial, domestic and commercial wastewater.

Box D.5: Waste to Energy

Methane from decomposing waste can be captured from landfills or waste collection ponds, and then safely destroyed by burning. The energy released from this reaction can be used to generate electricity via onsite power generators. The electricity created can be used within the waste facility or supplied to the electricity grid as a renewable source of generation. This waste-to-energy fuel source is classed as biogas and the emissions reductions derived from the displacement of fossil fuels are counted in the stationary energy sector.

Figure D.48: Waste emissions outcomes and contributors, 1990–2030

Figure D.48 shows the historical and projected emissions and contributors to Australia’s waste sector between 1990 and 2030. Between 1990 and 2012, waste emissions fell from 21 to 15 megatonnes of carbon dioxide equivalent. By 2030 waste emissions are projected to be 15 to 7 megatonnes of carbon dioxide equivalent. Relative to 2000, emissions reduction activities from waste management practices accounted for the majority of emissions reductions to date and are projected to continue to do so to 2030 under all scenarios. Increases in the volume of waste disposed will slightly offset the reductions made through improved waste management practices.

Source: Climate Change Authority calculations using data from The Treasury and DIICCSRTE 2013

Despite continued increases in recycling and other alternative waste treatments, the volume of waste deposited at landfills is projected by The Treasury and DIICCSRTE modelling to grow by 14 per cent (3 Mt CO2-e) from 2000 levels by 2030, due to continued population and economic growth. Over the same period, this modelling projects that, between the low and high scenarios, emissions can be reduced by between 58 and 70 per cent on 2000 levels. This includes a projected decline in solid waste emissions intensity of between 63 and 73 per cent on 2000 levels by 2030. Under these scenarios, there is projected to be from 4 to 5 Mt CO2-e emissions reduction from 2000 levels by 2020, and from 8 to 9 Mt CO2-e by 2030 (Figure D.48).

Wastewater volumes are projected to grow by nearly 50 per cent on 2000 levels by 2030. Over the same period, The Treasury and DIICCSRTE modelling shows that, under the same low and high scenarios, emissions can be reduced by between 10 and 20 per cent on 2000 levels. This equates to a projected decline in wastewater emissions intensity of between 40 and 46 per cent on 2000 levels by 2030. Under these same scenarios, there is projected to be between 0.1 and 0.6 Mt CO2e emissions reduction from 2000 levels by 2020, and between 0.3 and 0.7 Mt CO2e by 2030 (Figure D.48).

D10.3 Progress in waste emissions reduction

D10.3.1 Waste emissions reduction opportunities

The largest contributors to further emissions reduction in the waste sector are expected to be continued diversion of waste from landfill, methane capture and waste-to-energy. The activities are driven by a range of regulatory drivers, policy drivers and market-based incentives.

Alternative waste treatments have grown significantly since 1990, resulting in a significant amount of waste being diverted away from landfill (see Table D.7). Since this time, a major driver for the growth of alternative waste treatments has been the impact of regulatory frameworks. These have operated at all levels of government and span local planning controls, environmental safeguards and community standards, and have served to direct waste streams away from landfill where feasible.

Australian states and territories have adopted a broadly similar hierarchy of waste resource management options, in the following order – avoidance of unnecessary resource consumption as the first preference; then adopting alternative waste treatments including reuse, reprocessing, recycling and energy recovery; and, as the last resort, disposal via landfill or effluent streams. Some states have embodied this hierarchy into legislation such as the Waste Avoidance and Resource Recovery Act 2001 (NSW).

Strategic policy frameworks have also been developed at all levels of government. The National Waste Policy, for instance, is a major national policy that was endorsed by COAG in 2009, and sets Australia’s waste management and resource recovery direction to 2020. In partnership with the states and territories, the policy establishes strategic direction and best practice in the areas of waste avoidance and waste diversion. The management of waste continues to be a strong policy focus for state governments. For example, New South Wales recently (2013) released a draft policy statement for public consultation in relation to the recovery of energy and resources waste streams, and Victoria recently (2013) released two draft waste strategies detailing how the state will invest in waste infrastructure and maximise resource recovery.

Recycling and other waste diversion activities are projected to increase under a no price scenario, contributing to the emissions reduction outlined earlier. In the future, waste avoidance and alternative waste treatments are expected to be crucial in offsetting the growing quantity of waste generated which would otherwise be sent to landfill. With appropriate policies, incentives and funding in place, Blue Environment estimates that by 2030 as much as 70 per cent of all solid waste could be slated for resource recovery, reducing as much of 80 per cent of emissions (Blue Environment 2011, p. 8).

Since the late 1990s, there has been a growing number of market-based schemes put in place in many jurisdictions across Australia to encourage the reduction of waste and emissions. The diffusion of emissions capture and waste-to-energy technologies is influenced by demand, technology costs and regulations, and also by other market-based schemes which provide price incentives such as the Renewable Energy Target (RET). Under the RET, waste facility operators earn certificates for generating electricity which feeds into the National Electricity Market (NEM). The RET commenced in 2001 and was the first national policy driver to encourage waste methane capture for electricity generation.

Table D.7: Total national generation of waste and disposal to landfill, 1940–2007

Year

1940

1950

1960

1970

1980

1990

2000

2007

Waste generated (Kt)

9 600

10 100

15 200

17 700

17 100

16 400

25 600

42 700

Disposed to landfill (Kt)

9 600

10 100

15 200

17 700

17 100

16 400

19 600

21 300

Landfilled waste (%)

100

100

100

100

100

100

77

50

Source: Modified from Department of the Environment, Water, Heritage and the Arts 2010

ClimateWorks (2013) noted that, between 2001 and 2011, waste operators were credited with over 6 GWh of electricity generation under the RET, representing more than 7 per cent of large-scale renewable energy generation. Waste-to-energy technologies have grown sufficiently in scale and may soon contribute about 800 GWh of electricity into the NEM annually (SKM 2012). There is enough generation capacity from captured methane to power more than 200,000 homes, with an additional 45 MW of new landfill electricity generation projects currently in development, and a further 18 MW under assessment.

The modelling undertaken by The Treasury and DIICCSRTE includes the impact of the RET in all scenarios. Under the no price scenario, the small emissions reduction projected to 2030 can be attributed to a combination of factors, including the continuing impact of the RET.

In addition to the national RET, state-based schemes promoting effective treatment or diversion of waste have also contributed to the diffusion of emissions reduction technologies. The GGAS operated in New South Wales from 2003 to 2012 and provided operators with credits to capture emissions and certificates for electricity generation from landfill gas, similar in function to the RET. This scheme helped to incentivise the uptake of landfill gas capture technologies by providing landfill operators with additional revenue streams via the market for offset credits. This scheme was closed in 2012. The CFI now offers incentives for eligible landfill gas capture projects.

The CFI also provides price incentives for the reduction of emissions associated with legacy waste (waste deposited prior to 1 July 2012). Since its introduction, the CFI has registered more projects related to waste than from any other sector. According to the Clean Energy Regulator, as at October 2013, the CFI has over 60 registered waste projects involving gas capture, combustion and diversion, resulting in about 2 million Australian carbon credit units being issued, representing a reduction in emissions of about 2 Mt CO2-e. The CFI has also provided price incentives to landfill operators to install gas-capture technologies. As only legacy waste is eligible for CFI credits, the CFI is projected to be most pronounced in the first few years of operation, and will decline into the future as the emissions from legacy waste decline.

The price difference between landfilling and alternative waste treatments is expected to shrink under the low, medium and high scenarios, which would make alternative waste treatment a more attractive option. There is some evidence that reducing the price difference of landfill relative to alternative waste treatments drives waste streams away from landfill, and makes alternative waste treatment a more attractive option to pursue (Productivity Commission 2006). This has previously been addressed via increased landfill levies in some Australian states and in the United Kingdom (UK Committee on Climate Change 2013).

D10.3.2 Barriers to waste emissions reduction

Due to a range of pricing, demand and regulatory differences across states and municipalities, the level of landfill diversionary activity differs, indicating that additional emissions reduction opportunities may exist.

The installation of new technologies involves large capital costs that may take an extended period of operation to recover. This suggests that a strong and stable price incentive or a clear and enforceable regulatory requirement would be needed to further incentivise investment in these technologies.

New waste treatment technologies and processes, such as food and e-waste treatment and thermal treatment plants, may also face hurdles with community acceptance, land availability, local planning requirements and funding.

The level of demand can also be a barrier to effective waste diversion or emissions reduction, as towns in rural and regional areas often do not generate enough waste for operators to justify investing in costly alternative waste treatment facilities or technologies.

1 Large scale is taken to be annual sequestration of at least 0.8 Mt CO2 for coal-fired power plants or 0.4 Mt for gas-fired plants (GCCSI 2013c).

2 Based on a scenario that limits global emissions concentrations to 450 parts per million (ppm) in 2050.

3 Based on light vehicle fleet average emissions targets of 190 g CO2/km from 2015 and 130 g CO2 km from 2020.