The role of natural gas in Australia’s future energy mix McKinsey Australia and Energy Insights June 2016
Authored by: Christiaan Heyning João Segorbe
Cover image: Saxon rig at Fairview. Image courtesy of Santos.
The role of natural gas in Australia’s future energy mix McKinsey Australia and Energy Insights June 2016
Pluto LNG. Image courtesy of Woodside.
Contents Preface . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 Executive summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 1. Final energy consumption in Australia in 2030 . . . . . . . . . . . . . . . . . . . . . . . 9 2. Renewable energy will grow even in a business-as-usual scenario . . . . . . . 17 3. Opportunities for gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29 4. What would need to be done to make this happen? . . . . . . . . . . . . . . . . . 37 Conclusion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41 Appendices . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 45
The role of natural gas in Australia’s future energy mix
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Compressor station near Fairview (low impact). Image courtesy of Santos.
Preface Christiaan Heyning and Joao Segorbe are partners in McKinsey & Company’s Perth office.
The role that energy plays in the global economy is evolving. Energy consumption continues to grow driven by population and economic growth, but energy efficiency improvements are slowing or even reversing this trend in some countries and sectors. Improvements in the relative competitiveness of technologies such as grid-scale solar continue. And finally, climate and energy topics are becoming more intertwined. Australia is no exception to this. Blessed with an abundance of traditional and renewable resources, we have many options for how to structure the country’s energy system. This report examines a number of options for natural gas that Australia can choose from; it is not a comprehensive assessment of all options available. The intention is to contribute to the debate about how to meet Australia’s future energy needs by outlining the possibilities for domestic use of a fuel that Australia is set to become the biggest exporter of by 2020.1 To this end, we present a possible scenario for Australian energy consumption and supply in 2030, based on data and projections from the Bureau of Resources and Energy Economics, Australian Energy Market Operator (AEMO) and Independent Market Operator (IMO).2 We then discuss the opportunities for natural gas to fill new roles in the supply mix. The report concludes with a discussion about what it would take for these opportunities to be realised. This paper is the second from a series of reports into natural gas in Australia. It contributes to McKinsey’s mission to support the communities we operate in by addressing important, yet challenging issues. As with all research published by McKinsey, this work is independent and has not been sponsored in any way by any business, government or other institution. This paper has benefited from many sources of data and insight, and the authors are grateful for the perspectives from industry players, in particular, the secretariat and members of the Australian Petroleum Production & Exploration Association (APPEA). We also thank Santos, Woodside and Shell for the use of several of the images throughout this paper. McKinsey partners Christiaan Heyning (Perth) and Joao Segorbe (Perth) led this project. They were supported by a team consisting of Xiaolei Cao, Duncan Graham, Rahul Gupta and Angelos Platanias. For editing, visual and graphics support we thank Liza Cornelius, Therese Khoury, Clare Kitada and Lisa Maconie. We are grateful for advice from McKinsey’s Energy Insights, and colleagues Justin Bambridge, Giovanni Bruni, Antonio Castellano, Mike Ellis, Jane Goehring, Stephan Görner, Kai Graylee, Berend Heringa, Clive Hilton, Nicola Joyce, Jerard Koon, Rita Kriz, Peter Lambert, Keith Langlais, David Maisey, Michelle Marcoulier, Jan Tijs Nijssen, Mike Phillips, Ignace Proot, Helen Seidel, Pru Sheppard, Bram Smeets, Rembrandt Sutorius, and Charlie Taylor.
1 McKinsey & Company report, Sustaining Impact from Australia’s LNG industry, 2016. 2 More information on modelling methodology and references is contained in Appendix 1. The role of natural gas in Australia’s future energy mix
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NorthWest SeaEagle LNG tanker. Image courtesy of Shell.
2
The role of natural gas in Australia’s future energy mix
Executive summary There continues to be a significant role for gas in Australia’s energy supply mix to 2030 and beyond As Australia’s population and economy continue to grow, energy consumption is set to increase until 2030 – despite increased efficiency Australia is projected to increase its final energy consumption by a total of 21 percent between 2014 and 2030. With GDP forecast to increase by 2.7 percent per year on average, and an expected population of 30 million by 2030, the nation is projected to require an additional 873 petajoules of energy.3 This roughly equates to 75 percent of the energy consumed for all road transport in Australia today. These estimates take into account energy efficiency improvements from advances in technology and operational improvements. The projected efficiency gains are not enough to completely offset increases in consumption however. The biggest driver of this growth in energy consumption is expected to be increased demand from industry, led by the oil and gas sector. Energy consumption in that sector is projected to grow by 5.4 percent per year, to around 480 petajoules in 2030. This is driven by the quadrupling of Australia’s liquefied natural gas (LNG) capacity, which will be completed in the next few years. A second driver of overall consumption growth will be energy used for transport, which is forecast to grow by 0.8 percent per year on average to a total of around 1,800 petajoules in 2030. This is the net outcome of growth in the economy and population, partially offset by energy efficiency improvements.
The power supply will shift towards low-carbon technologies, while the fuel mix in other sectors will remain largely unchanged Australia’s fuel supply mix is currently 38 percent oil, 32 percent coal, 24 percent gas, with the remaining 6 percent from renewables and other sources. Direct consumption of fossil fuels and biofuels satisfies 78 percent of final energy demand in the industrial, residential and commercial, and transport sectors, while the remaining 22 percent of final energy consumption is supplied by centralised and distributed electricity generation.4 The energy supply scenario for this report does not explicitly model the impact of any new government or regulatory policies, and assumes that the Large-scale Renewable Energy Target (LRET) will be met by 2020. It is based on internally consistent assumptions, wherever possible obtained from Australian Government departments and regulators.5 This business-as-usual scenario assumes no major changes to the powertrain mix of Australia’s vehicle fleet, nor does it anticipate any major shifts in the fuel mix that supplies the industrial and residential and commercial sectors. In the power sector, modelling suggests that solar technology will improve competitiveness to the point where economics alone will dictate a
3 Australian Treasury, Intergenerational Report, 2015; Australian Bureau of Statistics. 4 Department of Industry, Innovation and Science, Australian Energy Statistics, 2015. 5 More information on modelling methodology and references is contained in Appendix 1. The role of natural gas in Australia’s future energy mix
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shift towards increased generation from renewables in the next decade. As a result, all new capacity built is projected to be renewable. The evolution of the power sector under business-as-usual assumptions, evolution of the power sector can be divided into three, five year long periods, each with a distinct dynamic: Before 2020, capacity additions are driven by the RET, which mandates a total of seven gigawatts of renewable capacity to be added between 2014 and 2020. Meeting this target will require 30 percent of renewable capacity projects currently undergoing feasibility assessment to be built, in addition to one gigawatt that has already been commissioned and two gigawatts where the final investment decision (FID) has been made.6 This capacity addition is modelled to lead to excess supply, so no other capacity is needed. The period between 2020 and 2025 does not require any additional capacity to be built. Increasing the utilisation of installed capacity could be enough to meet the projected growth in electricity consumption. Decommissioning some older thermal plants has been assumed to be delayed to after 2025. After 2025, new capacity might be required to respond to consumption growth and the decommissioning of some of Australia’s older thermal power plants. By this time, gridscale solar photovoltaic (PV) generation is expected to be the lowest cost technology based on its levelised cost of electricity (LCOE), not including subcritical black coal. Subcritical black coal is not expected to be considered for new generation capacity due to its high CO2-e emissions. As a result, all new capacity built after 2025 is projected to be solar. Across these three time horizons, the amount of electricity generated using natural gas would drop from 54 terawatt-hours in 2014 to 41 terawatt-hours in 2030, mostly through displacement by renewable technology. This represents a reduction in share of generation from 22 percent to 15 percent. The share of electricity generated by renewables could increase to 37 percent in 2030, up from 14 percent in 2014. Such growth is against a backdrop of growth in total generation from 248 terawatt-hours in 2014 to 282 terawatthours in 2030. The role of gas-fired power generation will increasingly be to complement intermittent generation from renewables. In other sectors, the output from the business-as-usual modelling has natural gas playing a similar role in 2030 as it does today. In industry it is expected to be an important source of heat and feedstock, with most of the increase in volume driven by its use as fuel for LNG liquefaction. It is expected to continue to be used for heating in the residential and commercial sector. Its role as a fuel for transport is set to remain minimal, limited mostly to buses run by public transport operators. When energy for power is combined with energy used in other sectors, Australia’s total supply mix in 2030 would end up at 39 percent oil, 27 percent coal, and 25 percent gas, with the remaining 9 percent supplied by renewables and other sources. This equates to 43 billion cubic metres of gas, compared with 36 billion cubic metres of gas in 2014. 6 Department of Industry, Innovation and Science, Electricity Generation Major Projects, 2015. 4
The role of natural gas in Australia’s future energy mix
In this scenario, which does not take into account any future legislation, total emissions could be around 640 million tonnes of CO2-e in 2030. This would exceed the COP 21 emissions target for Australia.7 Not considered here are the effects of any emissions reduction policies other than the Renewable Energy Target (RET). For example, the impact of the Emissions Reduction Fund has not been modelled for this report.8
Areas where gas could play an expanded role The business-as-usual scenario assumptions lead to projected growth in demand for gas from 36 billion cubic metres to 43 billion cubic metres between 2014 and 2030.9 This report considers two drivers for varying the business-as-usual assumptions that could result in additional gas demand; economic, where switching to gas is assumed to reduce fuel costs, and environmental, where switching to gas would reduce CO2-e emissions. Eight options have been assessed in some detail. The first seven of these options are economic, while the eighth comes at a cost. All of the options reduce CO2-e emissions. By 2030 the combined yearly impact would amount to US$900 million in cost savings, CO2-e abatement of 10.2 million tonnes, and an increase in gas demand of 7.1 billion cubic metres per year by 2030.10 The options are: 1. Using natural gas to power Australia’s trucks 2. Convert mining trucks to run on LNG 3. Run Australia’s public transport buses on CNG 4. Use LNG as bunkering fuel for domestic ships 5. Switch to LNG for rail 6. Switch off-grid oil-fired power generation to gas 7. Switch on-grid oil-fired power generation to gas 8. Increase the utilisation of existing efficient gas plants
7 Department of Environment, Australia’s 2030 Emissions Reduction Target, 2015. 8 The objective of the Emissions Reduction Fund is to help achieve Australia’s 2020 emissions target of 5 percent below 2000 levels by 2020; Department of the Environment. 9 More information on modelling methodology and references is contained in Appendix 1. 10 Not including any capital expenditure required to retrofit existing equipment to run on gas, or to set up gas infrastructure. The role of natural gas in Australia’s future energy mix
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The five transport options to increase the use of compressed natural gas (CNG) and LNG make commercial sense, as gas is a lower cost fuel per unit of energy than diesel and gasoline. Trucks, public transport buses, mining haul vehicles, ships and rail are the most suitable candidates for a switch to natural gas, as their high utilisation shortens payback periods. Implementing all of these options in the transport sector could save US$1 billion per year and reduce CO2-e emissions by 1.7 million tonnes. Gas consumption would increase by 3.7 billion cubic metres of gas as a result. Of the three options in power generation the first two, which involve replacing oil-fired generation with gas-fired generation, are expected to be economic. They could reduce fuel costs by US$400 million and emissions by 1 million tonnes of CO2-e per year.11 Shifting power generation from coal towards existing, highly efficient combined cycle gas turbine (CCGT) plants would reduce CO2-e emissions, albeit at an economic cost. It would reduce CO2-e emissions by up to 7.5 million tonnes of CO2-e per year at an annualised fuel cost of US$400 million. Whether this option should be pursued would have to be weighed against the cost of competing emissions abatement opportunities. All options in the power sector combined could lead to an increase in gas consumption of 3.4 billion cubic metres per year. This increase would roughly offset the modelled decline in gas demand from the power sector which is expected in the business-as-usual scenario. The barriers to adopting natural gas for new uses in transport and power generation are likely to be surmountable. For transport, the oil and gas industry would need to gather the will and resources to build the required refuelling infrastructure to give users the same flexibility as they get from using diesel or gasoline. For example, setting up a CNG refuelling station can cost upwards of US$2 million, which means a network servicing routes between Australia’s major east coast cities could total US$300 to US$400 million. But there is a clear commercial case for doing so. Government might also choose to support this endeavour to get the ball rolling.
11 Assuming a diesel price of US$13 per gigajoule and a gas price of US$7.5 per gigajoule in 2030. 6
The role of natural gas in Australia’s future energy mix
For power generation, the same holds true: the gas industry would need to facilitate the move from oil-fired to gas-fired generation by supporting the necessary infrastructure investments. Increasing the utilisation of efficient gas fired generation to reduce emissions does not require any investment, however the right incentives would have to be in place to make the higher generation costs worthwhile. * * * Satisfying Australia’s future energy consumption while at the same time reducing emissions significantly will require a different approach to what has worked in the past. Overall consumption in 2030 is expected to be 21 percent higher than it is today, and the mix of fuels that supplies it will likely change as a result of increased renewable penetration and action to reduce CO2-e emissions intensity. The options and numbers presented in this report are intended to help inform the debate amongst society, businesses, policy makers and regulators about what this future could look like.
The role of natural gas in Australia’s future energy mix
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The role of natural gas in Australia’s future energy mix
1. Final energy consumption in Australia in 2030 Final energy consumption is set to increase as GDP and population growth outstrip energy efficiency improvements The Australia of 2030 is expected to have a population that is 25 percent bigger than is the case today, and an economy that is 55 percent larger.12 Many industrial sectors are set to increase their production as they bring new projects online and remove bottlenecks, while improving the energy efficiency of existing operations.13 And there will have to be more vehicles on the road to transport these extra people and goods. This chapter presents a ‘business-as-usual’ scenario for final energy consumption in 2030. The modelling assumes that current trends continue, with no radical energy efficiency improvements or behavioural changes impacting on energy consumption. It provides a backdrop against which a business-as-usual energy supply mix can be projected and alternative options explored; these follow in Chapters 2 and 3. The options identified in Chapter 3 centre on natural gas, based on the observation that Australia’s LNG industry is set to become the world’s biggest by 2020.14 There are many alternatives across other sectors and fuel types that are not covered here, and these alternatives should be included in any informed debate about the future of Australia’s energy supply. Data and predictions about the Australian economy have been sourced from Australian Government agencies and regulators wherever possible, and some additional assumptions have been made where external perspectives were not available.15 These inputs have been used with McKinsey’s proprietary Global Energy Perspectives (GEP) model to present a view on Australia’s final energy consumption in 2030. While these projections are useful to help us think about what the next 14 years might look like, they represent neither a desired outcome nor a forecast of the future.
The Australian economy is on track to consume significantly more energy in 2030 than it does today Final energy consumption in 2030 is expected to be around 21 percent higher than in 2014, which equates to 4,933 petajoules in absolute terms (see Box 1). This projected increase is the combined effect of a bigger population and increased GDP per capita, partially offset by an assumed average energy efficiency improvement of 9 percent by 2030.16
12 Australian Treasury, Intergenerational Report, 2015; Australian Bureau of Statistics. 13 ClimateWorks, Industrial Data Analysis Project, 2013; Interviews with technical experts. 14 McKinsey & Company report, Sustaining Impact from Australia’s LNG industry, 2016. 15 More information on modelling methodology and references is contained in Appendix 1. 16 Average across all sectors; measured as share of energy reduction due to energy efficiency improvements, divided by total final energy consumption. The role of natural gas in Australia’s future energy mix
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Energy efficiency, mostly driven by technological change, plays out in all sectors of the economy. Similar efforts are made in the mining sector, but a gradual reduction in ore grades and geological inflation may result in a higher consumption of energy per unit of output.17 There is considerable scope remaining to improve energy efficiency across the economy; adopting efficiency standards and technologies that have been shown to work elsewhere in the world should lead to an immediate efficiency benefit. As an example, options available to the trucking sector to improve routing, embed fuel efficient driving behaviour and reduce idle time could lead to a reduction in overall energy used by the sector of up to 6 percent.18 These efficiency improvements are expected to occur and are included in the business-as-usual scenario. At an economy wide level, improved energy efficiency is expected to translate to a 19 percent improvement in energy intensity per unit of GDP between 2014 and 2030.19 While this is a considerable impact, the increase will not be fast enough to offset overall demand (Exhibit 1). Exhibit 1
Final energy consumption is modelled to increase by 21% by 2030 Australian final energy consumption in petajoules1
▪ 2.7% expected GDP growth p.a.
▪ 1.5% expected population growth p.a.
▪ Up to 5 million ▪
additional passenger cars 120 billion expected additional TKM2
▪ 2.5-3.1% p.a. expected efficiency ▪ Anticipated 4x increase in LNG liquefaction capacity
improvement in passenger cars
▪ 0.9-1.2% p.a. expected efficiency ▪
improvement in the residential and commercial sector 0.1 % p.a. expected efficiency improvement in the industry sector
4,933 4,060
611 235
2014
-484
Growth in residential & commercial consumption
+21%
510
Growth in transport consumption
Growth in industrial consumption
Reduction due to energy efficiency
2030 modelled consumption
1 One petajoule is equivalent to 0.278 terawatt-hours, 0.026 billion cubic meters of natural gas, and 9.1 billion cubic feet of natural gas 2 TKM = Tonne Kilometers SOURCE: Department of Industry, Innovation and Science, Australian Energy Statistics, 2015; Bureau of Resource and Energy Economics, Australian Energy Projections to 2049-50, 2015
Box 1: Australia in 2030.
Australia’s population is set to grow at 1.5 percent per year, reaching 30 million in 14 years’ time. Over the same period Australia’s GDP is forecast to grow by 2.7 percent per year on average. Collectively, this translates to a 21 percent growth in GDP per capita. Without any energy efficiency improvements, the combined effects of a bigger and wealthier population would translate into consumption of 5,420 petajoules of energy in 2030, or roughly, a 33 percent increase compared with 2014. This reduces to 4,933 petajoules once energy efficiency improvements are factored in. 17 Geological inflation is a phenomenon whereby mines require more energy to operate over time as they become bigger and deeper. 18 ClimateWorks, Industrial Energy Efficiency Data Analysis Project, 2013. 19 Measured in megajoules per unit of GDP.
10
The role of natural gas in Australia’s future energy mix
Final energy consumption will grow unevenly across sectors Different sectors of the Australian economy will grow their energy consumption at different rates, as businesses change their production levels to meet demand and improve their energy efficiency in accordance with the opportunities available to them. The transport and residential and commercial sectors are expected to take bigger strides towards more efficient energy use, while industry is set to progress at a slower rate due to capital intensity and the long technical life of equipment (Exhibit 2).20 Exhibit 2
Final energy consumption is expected to grow at different rates across sectors Australian final energy consumption in petajoules1
4,060 316
1,356 91 145 384 227 510
2014-30 CAGR Percent
-484 78 284
64
42 15
449
4,933 364
Commercial
0.9
516
Residential
0.9
851
Mining and oil and gas
3.0
1,397
Industry
1.0
1,804
Transport
0.8
531 1,186
1,578
2014
Growth in consumption
Reduced consumption from energy efficiency improvements
2030 business-as-usual
1 One petajoule is equivalent to 0.278 terawatt-hours, 0.026 billion cubic meters of natural gas, and 9.1 billion cubic feet of natural gas SOURCE: Department of Industry, Innovation and Science, Australian Energy Statistics, 2015; Bureau of Resource and Energy Economics, Australian Energy Projections to 2049-50, 2015
Transport The transport sector is Australia’s largest consumer of energy, and usage is heavily influenced by GDP per capita. As Australians earn more, they spend more on travel and move more goods around the country – both on roads and in the air.21 It is estimated that 18 million passenger vehicles will be on Australian roads by 2030, an increase of 35 percent compared to 2014. This increase is significant – Australians are likely to be driving around 400 million more kilometres in 2030 than they do today.
20 Bureau of Resources and Energy Economics, Australian Energy Projections to 2049-50, 2015; ClimateWorks, Industrial Energy Efficiency Data Analysis Project, 2013. 21 Driverless cars, a shift to fast rail and other speculative technology developments have not been considered in the analysis. The role of natural gas in Australia’s future energy mix
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Australians will be flying more too. The aviation sector is expected to maintain rapid growth in passenger numbers over the next 15 years, driven by annual GDP per capita growth of 1.2 percent.22 The number of passenger kilometres flown could increase by up to 90 percent by 2030, which is set to have a significant impact on oil consumption considering aviation is powered almost completely by oil based aviation fuel. This extra activity across the transport sector will require an additional 226 petajoules of energy in 2030, even after factoring in fuel efficiency improvements (Exhibit 3). Exhibit 3
Final energy consumption in the transport sector is modelled to grow by 14% by 2030 Petajoules1
▪ ▪ ▪ ▪
▪ Up to 5 million ▪
additional passenger vehicles 120 billion expected additional TKM2
▪
2.5% p.a. expected improvement from gasoline vehicles 3.1% p.a. expected improvement from diesel vehicles 0.7% p.a. expected improvement from trucks 22% of new car sales expected to be electric vehicles or plug-in hybrids 1.4% p.a. expected improvement from the aviation sector
510 Other transport services and storage Marine Rail
1,578 53 52 303
268 172
45
25 0
-284 119
165
0
1,804 53
97
14
38
226
453
Aviation Road
1,157
2014 final energy consumption
1,164
Incremental demand driven by growth in the sector
Change in demand due to efficiency improvements
2030 modelled final energy consumption
1 One petajoule is equivalent to 0.278 terawatt-hours, 0.026 billion cubic meters of natural gas, and 9.1 billion cubic feet of natural gas 2 TKM = Tonne Kilometers SOURCE: Department of Industry, Innovation and Science, Australian Energy Statistics, 2015; Bureau of Resource and Energy Economics, Australian Energy Projections to 2049-50, 2015
Residential and commercial Residential and commercial energy use currently accounts for the smallest share of energy consumption across all sectors. Much of the energy used in this sector goes into heating or cooling.23 For example, a kitchen fridge can account for around 13 percent of a household’s energy costs.24 How much energy is consumed in this sector is influenced by climate, GDP per capita, population size and energy efficiency. Residential and commercial energy consumption growth is expected to be in line with population growth; by 2030, the residential and commercial sectors will represent around 18 percent of Australian final energy consumption, assuming growth of 0.9 percent per year.
22 Department of Infrastructure, Infrastructure and transport to 2030, 2014; Australian Treasury, Intergenerational Report, 2015; Australian Bureau of Statistics. 23 10 percent of energy use is for heating and 8 percent is for cooling. 24 Sustainability Victoria website. 12
The role of natural gas in Australia’s future energy mix
While GDP and population growth drive additional consumption, energy efficiency improvements are greater in the residential and commercial sector than in other sectors. This marginally reduces the sector’s relative contribution to overall consumption in 2030 to 18 percent, compared with 19 percent in 2014. Across the sector, we can expect to see energy efficiency improvements from improved insulation, and more efficient lighting and appliances. This trend is underpinned by rising retail power prices, which prompt consumers to look for opportunities to save on monthly power bills.25 This in turn drives technological change, as manufacturers improve the energy efficiency of their products to gain an advantage over rivals. Programs such as the Australian Government’s Energy Rating system, which consumers rate highly as a determinant of purchasing decisions, also play a role.26 Annual savings from these improvements amount to 115 petajoules per year in 2030, 58 percent of which manifests as reduced demand for power. Despite this efficiency gain, as Australians become wealthier their final energy consumption per capita increases. It is set to rise from 32 gigajoules per capita in 2014 to 39 gigajoules per capita in 2030 off the back of demand for heating and air conditioning, which are discretionary activities that increase in line with growth in GDP per capita (Exhibit 4).27 Exhibit 4 Final energy consumption in the residential and commercial sectors is modelled to grow by 15% by 2030 Petajoules1
▪
1.5% p.a. expected population growth 235 91
765
▪ ▪
0.9% p.a. expected improvement in the residential sector 1.2% p.a. expected improvement in the commercial sector -120 880
145
115 364
Commercial
316
Residential
449
2014 final energy consumption
516
Incremental demand driven by growth2
Change in demand due to efficiency improvements
2030 modelled final energy consumption
1 One petajoule is equivalent to 0.278 terawatt-hours, 0.026 billion cubic meters of natural gas, and 9.1 billion cubic feet of natural gas 2 Projections based on historical lognormal relationship between energy consumption and energy per capita SOURCE: Department of Industry, Innovation and Science, Australian Energy Statistics, 2015; Bureau of Resource and Energy Economics, Australian Energy Projections to 2049-50, 2015
25 Australian Bureau of Statistics. 26 Department of Industry, Innovation and Science, GEMS Review, 2015. 27 Demand for cooking, heating and air conditioning is assumed to be related to growth in GDP per capita. The role of natural gas in Australia’s future energy mix
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Mining, and oil and gas Mining and oil and gas production are energy intensive activities, which leads to a strong energy efficiency focus in the sector.28 Mining production has ramped up considerably over the past five years, but growth is expected to moderate based on subdued demand for commodities in China. Overall production from the sector is projected to increase by 0.7 percent per year. Energy use for existing operations is expected to grow over time as ore grades change and geological inflation sets in.29 In total, 16 percent of industrial energy in 2030 will be consumed by mining, which represents consumption growth of 1 percent per year. As discussed in Sustaining impact from Australian LNG operations, the LNG industry is set to become the biggest exporter of LNG globally.30 This growth will lead to a 5.4 percent per year increase in energy demand for oil and gas extraction and gas liquefaction until all LNG liquefaction trains currently under construction come online by 2020. New developments are expected to use 1.3 percent less energy than existing facilities (Exhibit 5). Exhibit 5
The ramp up of LNG production is accompanied by an increase in demand for gas to be used as fuel Billion cubic meters
Export capacity Gas demand
LNG production
Gas demand1
120 100
8 7 6
80 60 40
5 4 3 2
20
1
0 0 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
1 Fuel requirement for liquefaction process SOURCE: AEMO, National Gas Forecasting Report, (2015); IMO, Gas Statement of Opportunities, (2015)
28 Interviews with technical experts. 29 Interviews with technical experts; geological inflation is a phenomenon where mines require more energy to operate over time as they become bigger and deeper. 30 McKinsey & Company report, Sustaining impact from Australian LNG operations, 2016. 14
The role of natural gas in Australia’s future energy mix
Other industry sectors In 2014, other industries, including agriculture, chemicals and manufacturing, account for around 29 percent of Australia’s energy consumption. Consumption from these sectors will grow by a relatively modest 1 percent per year, leading to a decline of their overall share of industrial energy consumption to 28 percent in 2030 (Exhibit 6). Exhibit 6
Final energy consumption in industry sectors, including mining and oil and gas, is modelled to grow by 30% by 2030 Petajoules1
▪ ▪
40% expected increase in ammonia production 4x expected increase in LNG liquefaction throughput capacity 611
▪ ▪
1.3% expected decrease in energy requirement for new liquefaction projects2 0.1% p.a. expected efficiency improvement assumed for ‘other industry’3 -80
2,248
384 1,717 Mining and Oil and Gas
Industry
227
851
531
531
1,397
1,186
2014 final energy consumption
Incremental demand Change in demand driven by growth due to efficiency improvements
2030 modelled final energy consumption
1 One petajoule is equivalent to 0.278 terawatt-hours, 0.026 billion cubic metres of natural gas, and 9.1 billion cubic feet of natural gas 2 Based on projections by the AEMO 3 Includes non-ferrous metals, food and beverages, wood and wood products, and iron and steel SOURCE: Department of Industry, Innovation and Science, Australian Energy Statistics, 2015; Bureau of Resource and Energy Economics, Australian Energy Projections to 2049-50, 2015; Global Energy Perspectives
How will this additional consumption be supplied? The additional 873 petajoules projected to be consumed by Australia’s economy in 2030 will require a similar increase in fuel supply. How this additional supply is split between different fuels will be dictated by fuel prices in the future, the costs and availability of new and existing technologies, and by strategies to reduce emissions intensity. The next chapter provides a ‘business-as-usual’ scenario of how this demand could be met.
The role of natural gas in Australia’s future energy mix
15
Compressor station, near Fairview. Image courtesy of Santos.
16
The role of natural gas in Australia’s future energy mix
2. Renewable energy will grow even in a business-as-usual scenario Solar is expected to become increasingly competitive at the same time as Australia takes action to reduce emissions intensity Technological progress is expected to continue to lower the costs of many existing technologies and will create or commercialise new ones. As well as cost, producers and consumers also consider reliability and impact on the environment when deciding what fuels and energy technologies to use.31 This chapter outlines what Australia’s energy supply mix could look like under the same ‘business-as-usual’ assumptions that were modelled in Chapter 1. In this scenario, investment decisions are assumed to be made based on costs and regulatory settings that are already in place. For example, the modelling considers the impact of the existing RET on which technology is used for new power plants built before 2020. It doesn’t take into account any potential future legislation, nor does it include the impact of the Emissions Reduction Fund. Data and assumptions have been sourced from government departments and other external agencies, as well as from McKinsey’s extensive industry databases.32
Business-as-usual would result in a mostly similar fuel mix between 2016 and 2030, with the biggest change in the power sector Adopting a business-as-usual approach would result in an overall energy supply mix in 2030 that continues to rely on coal, oil, and gas. The power sector would be expected to see a shift towards lower emitting technologies; the model has renewable energy growing from 35 terawatt-hours in 2014 to 103 terawatt-hours in 2030, equivalent to 37 percent of overall power production. This translates to an increase in the share of renewables in the energy supply mix across all sectors in 2030, from 1 percent to 5 percent. The remaining 95 percent of final energy consumption would continue to be supplied by conventional fuels such as oil, coal, gas and biofuels. The business-as-usual scenario described here is set to result in emissions of 640 million tonnes of CO2-e in 2030, which would exceed Australia’s COP 21 target.33 This analysis does not account for the impact of the Emissions Reduction Fund, or any emissions reduction policies other than the RET.
Business-as-usual power generation continues to be mostly supplied by coal and gas, despite strong growth in renewables Power generation in a business-as-usual future would continue to be fuelled primarily by coal, despite strong growth in renewables as they become more cost competitive. Electricity demand is expected to grow by 1.2 percent per year, to a total of 267 terawatt31 Australian Bureau of Statistics. 32 More information on modelling methodology and assumptions can be found in Appendix 1. 33 Department of the Environment, The Australian Government’s action on climate change, 2016. The role of natural gas in Australia’s future energy mix
17
hours in 2030. This growth is driven by a combination of a bigger economy, increased population, and rising electrification (see Box 2), and moderated by an assumed decrease in transmission and own use losses from 11 percent in 2014 to 5 percent in 2030. Demand for on-grid generation is also reduced by the increasing penetration of rooftop solar PV and storage systems. In a business-as-usual scenario, off-grid generation is assumed to increase its share of total power generation from 6 percent today to 10 percent in 2030.34 Electricity supply has been modelled using the following approach. Available capacity is derived by taking into account both retirements and new capacity which is reasonably likely to be built, either because it is mandated by the RET or because it has already been committed to by industry.35 This capacity is then utilised based on its short run marginal cost; the cheaper plants are run first, followed by more expensive ones. The model then adds additional capacity to the supply mix if existing capacity is not enough to meet demand, or when demand can be met more cheaply by adding new, lower cost capacity. The choice of what technology to use for any new capacity is based on cost; whichever technology is modelled to have the lowest LCOE at the time the capacity is required is added to the system. The LCOE for a given generation technology depends on the cost of building and maintaining the plant, as well as expectations about fuel prices over the lifetime of the facility. LCOE is therefore highly dependent on the price of gas, coal and oil and, for renewable energy, the expected energy yield. The model assumes that seven gigawatts of renewable generation capacity will be added to the National Electricity Market (NEM) and South West Interconnected System (SWIS) between 2014 and 2020. This is the amount of new renewable capacity required to meet the LRET by 2020.36 Of the seven gigawatts expected to be added, one gigawatt has already been commissioned and projects totalling two gigawatts are post-FID.37 The additional four gigawatts have been assumed to come from the 15 gigawatts worth of renewable projects that are currently undergoing feasibility assessment. Retirements between now and 2030 are assumed to remove 12 gigawatts of generation capacity from the system as power plants reach the end of their economic lives. This includes 9.3 gigawatts in the NEM and 2.5 gigawatts in the SWIS.
Box 2: Electrification.
Electrification is a phenomenon where electricity is increasingly used to power activities that historically had relied on other sources of energy. For example, buying a dishwasher increases electrification by using electricity to achieve what had previously been done by hand. Electrification is broadly driven by three factors: a shift away from gas and oil to generate heat in the residential and commercial, and industry sectors; an increase in the penetration of appliances in homes and offices; and a shift towards electric vehicles − although the impact is currently small.
34 Includes both captive and distributed generation. 35 This includes all post-FID projects and 30 percent of capacity from projects currently undergoing feasibility assessment. 36 Clean Energy Regulator, Administrative Report and Annual Statement, 2015. 37 Department of Industry and Science, Electricity Generation Major Projects, 2015; Post-FID projects are Mortlake South Wind Farm, Broken Hill Solar Farm, Kogan Creek Solar Boost Project, Moree Solar Farm, Hornsdale Wind Farm, Glen Innes Wind Farm, Lincoln Gap Wind Farm, Ararat Wind Farm, Bulli Creek Solar Farm Stage 1, and Gannawarra Solar Farm. 18
The role of natural gas in Australia’s future energy mix
All in all, results from the model identify a requirement for an extra 34 terawatt-hours of power to be generated in 2030 compared to 2014, to deal with the impact of increased consumption. In the business-as-usual scenario this translates to a requirement for 17 gigawatts of new solar capacity, on top of the seven gigawatts that is assumed to be built between 2014 and 2020 to meet the LRET. At that time, solar is expected to have the lowest LCOE in the SWIS (Exhibit 7). In the NEM, subcritical black coal is expected to remain cheaper than solar until 2030. This technology has been excluded from analysis based on the assumption that its higher emissions intensity and a desire to avoid lock-in will preclude it from getting the required approvals.38 Lock-in is where investment decisions made now have long-term negative impacts when future changes render the asset obsolete or undesirable, but it keeps operating due to its long technical life. As a result, all new capacity added to the power systems between 2025 and 2030 are assumed to be solar (Exhibit 8).39 Following is an analysis of the expected on-grid power generation mix across the NEM and the SWIS, which combined account for around 90 percent of Australia’s total power generation (see Box 3). Exhibit 7 The levelised cost of electricity for different technologies is modelled to change over time Levelised cost of electricity in US$ per megawatt-hour
Subcritical-black coal
Solar PV
Supercritical-black coal
Onshore wind
CCGT
South West Interconnected System
National Electricity Market
120
120
100
100
80
80
60
60
40
40
20
20 0
0
2015
20
25
2030
2015
20
25
2030
SOURCE: Department of Industry, Innovation and Science, Australian Energy Statistics, 2015; Bureau of Resource and Energy Economics, Australian Energy Projections to 2049-50, 2015; International Energy Agency, World Energy Outlook, 2015; Clean Energy Regulator, Administrative Report and Annual Statement, 2015
38 Smith School of Enterprise and the Environment, Subcritical Coal in Australia: Risks to Investors and Implications for Policymakers, 2015; No subcritical coal has been built in the NEM since the Redbank plant was commissioned in 2001. 39 More information on modelling methodology and assumptions can be found in Appendix 1. The role of natural gas in Australia’s future energy mix
19
Exhibit 8 Renewables are modelled to replace thermal generation in both grids Percent of total power generation in terawatt-hours South West Interconnected System
National Electricity Market
22
210 193 4%
19 Renewables Oil
8% 2%
40%
0%
8%
14%
Gas
49%
26%
8% 8%
1%
0%
Renewables Hydro Oil Gas
31% 73% 58% Coal
40%
2014
Coal
28%
2030
2014
2030
SOURCE: Department of Industry, Innovation and Science, Australian Energy Statistics, 2015; Department of Industry, Innovation and Science, Electricity Generation Major Projects, 2015; Bureau of Resource and Energy Economics, Australian Energy Technology Assessment, 2012; Clean Energy Regulator, Administrative Report and Annual Statement, 2015
Box 3: Australian electricity transmission grids.
20
Australia has two main electricity transmission grids, the NEM and the SWIS. The NEM accounts for around 80 percent of Australian electricity transmission and serves Queensland, New South Wales, Victoria, Tasmania, and South Australia. The SWIS accounts for around 8 percent of transmission and serves the south west area of WA, including Perth. The grids are not connected in any way, and are therefore modelled separately in this analysis. There are also a number of smaller grids, such as the Northern Territory Electricity Network (NTEN) and Mt Isa grid, which serve remote communities and large mining operations. This analysis has modelled the NEM and SWIS in detail, and aggregated the remaining grids as ‘other generation’.
The role of natural gas in Australia’s future energy mix
Fuel mix of the National Electricity Market The NEM is the largest power grid in the country, accounting for over four-fifths of Australia’s total power generation. Results from modelling a business-as-usual scenario can be broken down across three time horizons (Exhibit 9): Prior to 2020: Capacity additions are driven by the need to meet Australia’s LRET target, which results in all new capacity being built using renewable technology. Between 2020 and 2025: Capacity installed prior to 2020 is expected to be enough to cope with expected demand, and no additional power plants need to be built.40 Beyond 2025: Grid-scale solar PV is expected to have the lowest LCOE of all technologies except subcritical black coal, and is therefore selected for all new generation capacity.41 Exhibit 9
Installed generation capacity is modelled to grow from 50 GW in 2014 to 61 GW in 2030 in the National Electricity Market Gigawatts of on-grid installed capacity
Coal
Oil
Gas
Hydro
Renewables
14 7 50 2
-2
54 7
0
0
9
9
8 1
8 1
11
10
10
28
27
27
7 1
2014
0 1 1
0
Committed Decommissioned plus 4GW currently in feasibility1
2020
New Decommissioned capacity modelled
2025
61
-7
54
0
3 5
23
8 0 7
23
New Decommissioned capacity modelled
2030
1 The 2 GW Bulli Creek solar farm is assumed to be developed in 8 stages of 250 MW each and come online at 500 MW per year over 2017-20 SOURCE: Department of Industry, Innovation and Science, Australian Energy Statistics, 2015; Department of Industry, Innovation and Science, Electricity Generation Major Projects, 2015; Bureau of Resource and Energy Economics, Australian Energy Technology Assessment, 2012; Clean Energy Regulator, Administrative Report and Annual Statement, 2015
40 Assumes that thermal capacity can be extended beyond its technical life. 41 Subcritical black coal has been excluded from analysis based on the assumption that its higher emissions intensity and a desire to avoid lock-in will preclude it from getting the required approvals. No subcritical coal has been built in the NEM since the Redbank plant was commissioned in 2001. The role of natural gas in Australia’s future energy mix
21
Australia’s 2020 LRET target requires seven gigawatts of new renewable capacity to be brought online between 2014 and 2020, of which 95 percent is expected to be installed in the NEM. One gigawatt of this requirement has already been installed since 2014, which leaves six gigawatts to be built. This target can be met by completing all post-FID projects, and 30 percent of the projects that are currently being assessed for feasibility.42 Assuming this occurs, the NEM would have a total of 54 gigawatts of installed capacity by 2020 to meet an assumed peak demand of 38 gigawatts. The 54 gigawatts of capacity assumed to be in place in 2020 would be enough to meet projected demand until 2025. Power consumption in the business-as-usual scenario is expected to grow by 1.3 percent over this period, with peak demand in 2025 projected to be 40 gigawatts. This demand can be met without building any additional capacity, assuming the planned retirement of 1.4 gigawatts of capacity can be postponed to after 2025.43 Modelling suggests that after 2025 new capacity would have to be added to the NEM to meet projected consumption growth. By the time this capacity is added, LCOE for solar is projected to be lower than for other generation technologies excluding subcritical black coal.44 As a result, the model assumes that all new capacity added after 2025 would be solar PV. By 2030 overall power generation in the NEM is modelled to have reached 210 terawatthours, with peak demand hitting 42 gigawatts. This would necessitate the development of 14 gigawatts of grid-scale solar PV capacity. It is important to note that the precise timing of plant retirements and corresponding capacity additions can be smoothed. See Box 4 for an overview of how the model selects which technology to build and run. Overall the business-as-usual scenario projects total capacity in the NEM of 61 gigawatts in 2030, of which 50 percent is renewables, 37 percent is coal, 12 percent is gas, and the remaining 1 percent is oil. Generation dispatched into the system is expected to be 58 percent coal, 34 percent renewables, and 8 percent gas.
Box 4: Generation capacity and dispatch.
New power plants are built according to their LCOE. LCOE is the net present value of the expected cost to deliver each unit of generation, based on all lifetime costs associated with the asset. Once a plant has been built, electricity is dispatched to the grid based on the plant’s Short Run Marginal Cost (SRMC). This means that plants with the lowest SRMC will meet demand until they have reached their maximum utilisation, at which point plants with a higher SRMC will begin supplying electricity to the grid.
42 Department of Industry, Innovation and Science, Electricity Generation Major Projects, 2015. 43 Plants would have to continue operating beyond their technical lifetime, although such extensions are common. 44 Assumes no subcritical coal will be built in the future due to high emissions intensity. No subcritical coal has been built in the NEM since the Redbank plant was commissioned in 2001. 22
The role of natural gas in Australia’s future energy mix
Fuel mix of the South West Interconnected System The SWIS represents 8 percent of Australia’s total power generation. The model expects generation to increase by 13 percent between 2014 and 2030, with a shift in the supply mix away from coal and gas, and towards renewables. Under business-as-usual assumptions, total gas generation is modelled to decline by 30 percent to seven terawatt-hours, generation from renewables is expected to increase by fivefold to nine terawatt-hours, while coal generation declines by 21 percent to six terawatt-hours. Similar to results in the NEM, changes can be clustered across three time horizons. Prior to 2020, the model expects 320 megawatts of new renewable generation capacity to be brought online. This is expected to be met by 230 megawatts from wind projects and 90 megawatts from solar projects. Total installed capacity by 2020 is set to be 6.3 gigawatts. Between 2020 and 2025, extending the life of 750 megawatts of thermal capacity should be enough to meet demand out to 2025. New capacity equalling 3.1 gigawatts is forecast to be built between 2025 and 2030. This is expected to be sourced entirely from solar PV, which is even more cost competitive in the SWIS than in the NEM owing to more sunshine (Exhibit 10).45 Exhibit 10 Installed generation capacity is modelled to grow from 6.5 GW in 2014 to 7.5 GW in 2030 in the South West Interconnected System Gigawatts of on-grid installed capacity
Coal
Oil
Gas
Renewables
7.5 6.5 0.5 0.5
-0.6 0.1 0.5
0.3
6.3
6.3
0.8
0.8
0.5
0.5
-1.9 0.1 0.9
3.1
3.8
0.9 3.7
3.1
0.5
3.1
2.2 1.9
1.9
1.9 1.0
2014
Decommission
Committed and in feasibility
2020
Decommission
New capacity modelled
2025
Decommission
New capacity modelled
2030
SOURCE: Department of Industry, Innovation and Science, Australian Energy Statistics, 2015; Department of Industry, Innovation and Science, Electricity Generation Major Projects, 2015; Bureau of Resource and Energy Economics, Australian Energy Technology Assessment, 2012; Clean Energy Regulator, Administrative Report and Annual Statement, 2015
45 Interviews with technical experts. The role of natural gas in Australia’s future energy mix
23
Non-power sectors remain dependent on non-renewable fuel in the business-as-usual scenario Transport Transport is assumed to continue its reliance on oil in the business-as-usual scenario. Australia’s vehicle fleet is set to consume 1,164 petajoules in 2030, supplied by 51 percent petrol, 46 percent diesel, and less than 3 percent for LPG, gas and electricity. The fuel supply mix would be dictated by the fuel mix of the vehicle fleet and the kilometres travelled annually. As most vehicles aren’t converted from one fuel type to another, and the average vehicle in Australia remains on the road for 25 years, the scenario assumes slow changes to the fuel mix.46 While electric vehicles are assumed to account for 22 percent of new sales by 2030, the slow turnover of existing stock means that the fleet is expected to be less than 1 percent electric by this time.47 Chapter 3 investigates options where natural gas could play a bigger role as fuel for transport than what is expected in the business-as-usual scenario. The fuel mix for aviation is expected to remain unchanged, as air travel is entirely dependent on aviation turbine fuel and there are no fuel technology breakthroughs on the horizon.
Residential and commercial The scenario modelled assumes the fuel mix in the residential and commercial sector will remain unchanged in 2030 compared with 2014. Electricity would supply 47 percent and 73 percent of energy consumption for the residential and commercial sectors respectively. More natural gas is set to be used in the residential sector than the commercial sector, with its 35 percent penetration rate mostly used for heating and cooking. This assumes that the ratio of buildings with access to natural gas infrastructure remains similar to today, as penetration rates are already high, and that gas remains a lower cost option for heating than using electricity.
Mining, and oil and gas Of the energy supplied for mining, 52 percent is expected to come from natural gas, 29 percent from diesel, 17 percent from electricity, and the remaining 2 percent from other fuels by 2030. The majority of diesel would be used for mining haul trucks, with a small amount directed towards backup power generation. The primary source of energy for Australia’s new LNG liquefaction plants would continue to be ‘own consumption’ of natural gas for compression and power generation within the plant, with the majority of energy needs supplied by the plants’ own feed gas.48
46 Australian Bureau of Statistics. 47 ClimateWorks The Path Forward for Electric Vehicles in Australia, 2016; Energy Supply Association of Australia, Sparking and Electric Vehicle Debate in Australia, 2013; Australian Bureau of Statistics. 48 More information on modelling methodology and assumptions can be found in Appendix 1. 24
The role of natural gas in Australia’s future energy mix
Materials The materials industry, which includes non-ferrous metals, non-metallic minerals and other basic materials, represents a large part of Australia’s industrial activity. The energy supply mix is currently predominantly comprised of electricity and gas, which are used for processing and heating. Historical trends indicate higher electrification of the industry, as manufacturers move towards more advanced technologies in their production processes.49 In the business-as-usual scenario, electricity is expected to grow by 3 percentage points by 2030 to represent 37 percent of the energy consumed in the sector, while natural gas remains at a steady 38 percent of the supply mix. The remaining 25 percent is supplied by a mix of bituminous coal (7 percent), fuel oil (6 percent), and other oil products.
Food and agriculture The food and agriculture sector is fuelled around 35 percent by oil, mostly for transport, and 30 percent by biomass derived from agricultural waste, which is used for the production of energy.50 Historically, there has been a trend of substituting oil for biofuels. Developments in the production of biofuels from waste, coupled with the sector’s continually improving ability to recycle larger portions of waste to use for energy, point to the reduction of oil products to 24 percent of the mix by 2030 and the increase of biofuels to 52 percent. Gas has been modelled to decline slightly to 13 percent and the share supplied by electricity to decline to 8 percent, while other fuel types account for the remaining 3 percent.
Other industry sectors Other industry sectors, such as iron and steel production, are not expected to see significant shifts in their supply mix. The mix for these sectors today is 38 percent gas, 24 percent oil, 21 percent electricity, and 14 percent coal, with the remaining 3 percent from other sources such as biofuels. The major shift to 2030 is a slight decrease in oil and coal usage, replaced with gas and biofuels. The split in 2030 is set to be 40 percent gas, 22 percent oil, 22 percent electricity, 12 percent coal, and the remaining 4 percent from other sources such as biofuels.
49 ClimateWorks, Pathways to Deep Decarbonisation in 2050, 2014. 50 Department of Industry, Innovation and Science, Australian Energy Statistics, 2015. The role of natural gas in Australia’s future energy mix
25
In total, this leads to an energy system in 2030 that is fuelled 39 percent by oil, 27 percent by coal, 25 percent by gas, 5 percent by renewables, with the remaining 4 percent supplied by a mix of other fuel types. This breakdown can be seen in Exhibit 11. Exhibit 11 Oil, gas and renewables are all expected to grow their absolute contribution, while coal declines Petajoules, Australian primary energy supply
5831 212
66
68
1,402
-104 Retirement of 6.7 GW of coal capacity
245 Increased gas usage for liquefaction projects
277
Growth in transport and the mining sector
2,238
221
Biofuels
Hydro
Oil
Renewables
Gas
Coal
41
-4
6508 62
289
253
1,647
Installation of 24 GW of renewable power generation capacity
2,515
Key drivers
1,846
2014
1,742
Change in coal
Growth in gas
Growth in oil
Growth in Growth in renewables biofuels
Change in hydro
2030
SOURCE: Department of Industry, Innovation and Science, Australian Energy Statistics, 2015; Department of Industry, Innovation and Science, Electricity Generation Major Projects, 2015; Bureau of Resource and Energy Economics, Australian Energy Technology Assessment, 2012
Under business-as-usual, gas would play a similar role in 2030 as it does today Currently, Australia consumes 36 billion cubic metres of natural gas for heating, power generation, and as feedstock for many industrial processes. Gas does not play a big role as a source of energy for transport, despite having a lower cost per unit of energy than diesel or gasoline. The use of gas in 2030 is not projected to be radically different in the business-as-usual scenario. There are two changes to note however. Firstly, there is an increase in the use of gas as a source of energy for LNG liquefaction, which is expected to be supplied by the LNG trains’ own feed gas. Secondly, there is a slight decrease in gas consumption in the power sector as gas-fired generation capacity is retired and new capacity is met by renewables (Exhibit 12). There are opportunities for gas to expand its role in the future, while at the same time lowering fuel costs and CO2-e emissions. These opportunities are presented in the following chapter.
26
The role of natural gas in Australia’s future energy mix
Exhibit 12 Most of the expected growth in gas consumption is driven by increased LNG liquefaction volumes Billion cubic metres
Transport
Industry
Mining and oil and gas
Power
Residential & commercial
36 0
5
1
6
-3
0
2
43 0 12
5
6
12
14
14
11
2014
4.7 GW of retired capacity and reduced utilisation of gas plants Power generation
Growth in Increase demand in demand from industry for LNG liquefaction
Feedstock & heating
Increase in residential and commercial demand
Heating needs
Increased demand from vehicles running on gas
2030 business-asusual consumption
Combustion
SOURCE: Department of Industry, Innovation and Science, Australian Energy Statistics, 2015; Department of Industry, Innovation and Science, Electricity Generation Major Projects, 2015; Bureau of Resource and Energy Economics, Australian Energy Technology Assessment, 2012
The role of natural gas in Australia’s future energy mix
27
28
The role of natural gas in Australia’s future energy mix
3. Opportunities for gas Economic opportunities exist for a larger role of gas in transport and power generation Chapters 1 and 2 of this report outline the role for gas in a business-as-usual scenario. This chapter investigates options for gas to play new roles by changing some of the business-asusual assumptions. Outlined below are seven options where switching to natural gas could lead to positive economic and environmental impacts, five in the transport sector and two in the power generation sector. Fully implementing all of them could create value in the order of US$1.4 billion per year based on the consumption growth modelled in Chapter 1. They are expected to have the additional benefit of reducing up to 2.7 million tonnes of CO2-e per year. There is one additional opportunity in the power sector where gas can help to reduce emissions, albeit at a higher economic cost. Chapter 4 goes on to discuss what may need to change for these options to be realised.
Transport costs can be reduced by using natural gas, but refuelling infrastructure would need to be built Gas is currently lower cost than petrol or diesel on a per unit of energy basis. While this has been true for some time now, power train technology that runs on natural gas has not been widely adopted. There is a chicken-and-egg problem; the number of LNG or CNG refuelling stations around the country is quite low, and less than 0.4 percent of vehicles currently use natural gas as fuel.51 This is changing however. For example, 38 percent of the bus fleet run by public transport operator Transperth is powered by CNG.52 In addition to cost savings from fuel switching, natural gas emits around 20 percent less CO2-e per kilometre and almost no particulate matter.53 Below are five options where gas, either in the form of CNG or LNG, could be used for transport. If implemented fully, these could create economic value of around US$1 billion annually, while also reducing Australia’s CO2-e emissions by up to 1.7 million tonnes in 2030 (Exhibit 13).54
51 Australian Bureau of Statistics; Energy Supply Association of Australia, Developing a market for Natural Gas Vehicles in Australia, 2014; Based on the business-as-usual scenario modelled in Chapters 1 and 2. 52 Public Transport Authority, Annual report, 2015; the remainder of the fleet is diesel. 53 CNG has a lower price of A$1.1 per litre of diesel equivalent, compared with a diesel price of A$1.3 to A$1.4 per litre of diesel equivalent, and lower emissions levels. These fuel costs include capital and operational expenditure required to set up CNG refuelling stations. Natural gas vehicles emit 56 kilograms of CO2-e per terajoule while diesel vehicles emit 74 kilograms of CO2-e per terajoule. 54 Fuel cost savings only. Excludes capital expenditure for infrastructure. The role of natural gas in Australia’s future energy mix
29
Exhibit 13 There are opportunities for gas in the transport sector Assumptions
Impact of using natural gas for transport
2030 fuel price 2 A$/DLE Lever—assumption 1.4 1.1
1.0
NGV trucks: 15% of TKM fleet (covering articulated trucks on key highways) LNG for mining trucks: 2500 mining trucks at top 50 mines
Emission factor kgCO2e/TJ
74 56
56
CNG buses: 100% of the public transport bus fleet in Melbourne, Sydney, Perth, Adelaide and Brisbane LNG bunker fuel for ships: 50% of the coastal ship fleet LNG fuel for locomotives (mining): 750 trains on major iron ore and coal routes
Diesel CNG LNG
2030 emission abatement MtCO2e 0.4
0.5
0.4
0.3
0.2
Total
1.7
Incremental gas Change in Abatement demand fuel costs costs1 bcm US$ Billions US$/tCO2e 0.9
-0.2
-160
1.1
-0.4
-420
0.9
-0.2
100
0.6
-0.1
-30
0.2
-0.1
-130
3.7
-1.0
-140
1 Computed based on annualised capex for retrofitting equipment and savings in fuel costs 2 Capex and opex costs for setting up LNG and CNG refueling stations are included in the fuel price SOURCE: IPCC; Interviews with technical experts; Core Energy Group, Commercial Assessment of CNG and LNG as transport fuels, (2015)
Use natural gas to power Australia’s trucks Trucks play a big role in hauling Australia’s freight around the country, and 99.8 percent of the fuel used by them is diesel.55 Assuming that the majority of Australia’s road freight is transported by large, articulated trucks, such as B-doubles, 50 percent of tonne kilometres travelled each year could be completed by 15 percent of the nation’s truck fleet.56 Transitioning 15 percent of Australia’s trucks to run on natural gas could save the economy US$200 million in fuel costs. At the same time CO2-e emissions could be reduced by 0.4 million tonnes per year, while increasing consumption of natural gas by 0.9 billion cubic metres per year. Factoring in conversion costs of US$36,000 for each existing truck that switches from diesel to gas, the payback could be around 4.5 years.57 In a more aggressive scenario, moving all trucks to natural gas could save US$500 million in fuel costs each year while also abating one million tonnes of CO2-e. This scenario is expected to require an additional 2.5 billion cubic metres of gas.
55 Department of Industry, Innovation and Science, Infrastructure and Transport to 2030, 2015. 56 Assuming 50 percent of TKM are travelled on the main highways between Sydney, Melbourne, Adelaide, and Brisbane, with 80 percent of TKM from articulated trucks. Trucks are assumed to be retrofitted to natural gas vehicles (NGV) gradually, ending with 50 percent of the fleet converted by 2030. 57 Core Energy Group, Commercial Assessment of CNG and LNG as Transport Fuels, 2015/16. 30
The role of natural gas in Australia’s future energy mix
Convert mining trucks to run on LNG There are currently more than 3,000 mining haul trucks in use at Australian mines. Each year these trucks consume around four billion litres of diesel.58 Retrofitting 2,500 of these trucks to run on LNG could cost around US$300,000 per truck, but doing so represents an opportunity for mining operators to significantly reduce fuel costs. Including the cost of building refuelling infrastructure, transitioning to LNG could save up to US$400 million in fuel costs each year, while at the same time decreasing CO2-e emissions from these vehicles by 0.5 million tonnes.59 This switch is already starting to happen in the US. For example, Alpha Natural Resources has converted trucks to LNG at its Eagle Butte coal mine in Wyoming.60 Given Australia has reliable access to natural gas, there are opportunities for a similar conversion here.61 If all mining trucks ran on LNG, over 0.9 million tonnes of CO2-e could be abated – and natural gas consumption could increase by two billion cubic metres.
Run Australia’s public transport buses on CNG Many Australian public transport operators have already shifted some of their fleet to natural gas.62 CNG-fuelled buses produce 15 to 20 percent less CO2-e, and hardly any particulate matter compared with diesel. Converting all of Australia’s public transport buses to CNG in the capital cities of Melbourne, Perth, Sydney, Adelaide and Brisbane could reduce emissions by about 0.4 million tonnes of CO2-e per year. Fuel savings would be likely to approach US$230 million, with a payback period of 10 years once conversion costs of US$150,000 are taken into account. Buses are particularly suitable for lower cost slow-fill stations given that they may stay in a depot overnight (see Box 5).
Use LNG as bunkering fuel for domestic ships Limits on the level of sulphur allowed in marine fuels were reduced after 2012.63 Given LNG contains almost zero contaminants, it could be a viable option for ship owners and operators to meet this requirement and switch away from the heavy fuel oil commonly used at present. If LNG infrastructure existed at major ports in Australia, converting 50 percent of the domestic ship fleet to run on LNG by 2030 could save the Australian economy US$50 million each year through reduced fuel costs. CO2 emissions could be reduced by up to 0.3 million tonnes of CO2-e per year. Factoring in conversion costs of US$840 per kilowatt, the payback period for converting ships to LNG would be around 13 years. Beyond 2030, moving all ships to LNG could abate 0.5 million tonnes of CO2-e and require 1.1 billion cubic metres of gas. It is worth noting that there are technical challenges to be overcome in converting existing ships to LNG, so it is likely that demand will come from ships that are built specifically to run on the fuel. See Box 6 for a brief overview of Shell’s LNG bunkering trial in the port of Rotterdam. 58 2014 diesel consumption in mining was 200 petajoules. Assuming 60 percent of diesel is used for trucking, this translates into approximately 4 billion litres of diesel consumption. 59 Core Energy Group, Commercial Assessment of CNG and LNG as Transport Fuels, 2015/16. 60 Mining Magazine, Teck announces LNG haul truck pilot project, 2015. 61 McKinsey & Company report, Sustaining impact from Australian LNG operations, 2015. 62 Public Transport Authority, Annual Report, 2015. 63 Annex VI of the International Maritime Organization (IMO) International Convention for the Prevention of Pollution from Ships (MARPOL). The role of natural gas in Australia’s future energy mix
31
Box 5: The difference between CNG and LNG.
CNG and LNG are both made from natural gas. Because gas takes up volume, it needs to be condensed before it can be easily transported and stored. The difference between CNG and LNG is in how much compression takes place. CNG is natural gas that has been compressed by a factor of around 100, so you can fit 100 times more molecules in a given space than with uncompressed gas. LNG is natural gas that has been further compressed so that it becomes a liquid, which requires temperatures of -162 degrees centigrade. LNG has been compressed by a factor of around 600, so you can fit even more molecules into a given space than CNG. Doing this requires expensive, specialised equipment, so LNG is typically more expensive than CNG. This additional cost can become worthwhile during transport across large distances, such as happens with gas for export. CNG infrastructure for transport. Infrastructure to compress natural gas into CNG can be built anywhere with access to natural gas pipelines. There are two main types of CNG stations that can supply CNG for transport, time-fill and fast-fill. Time-fill stations connect the compressor directly to the vehicle and slowly compress the gas within the vehicle’s own gas tank. This takes time, but is typically lower cost to run and produces less heat while operating, which means that more gas can be compressed into the tank. Fast-fill stations compress gas into a CNG holding tank, from where it can be quickly transferred to a vehicle CNG tank in its compressed form. This method generally adds additional costs to the compression process, but has the advantage of being able to refuel a vehicle in a short period of time. Building a CNG refuelling station typically costs US$2 to $4 million. It may not require many refuelling stations to be built for CNG to become viable; fewer than 10 stations could be sufficient to cover the 800 kilometre Hume Highway between Melbourne and Sydney. LNG infrastructure for transport. Infrastructure to turn natural gas into LNG is considerably more expensive than for CNG. This additional cost is due to the requirement for gas to be cooled to -162 degrees centigrade before it turns into a liquid. Storing LNG is also more expensive than storing CNG, given the specialised tanks required to handle its low temperature. As a result, building an LNG refuelling station can cost upwards of US$60 million. When energy requirements are high or the desired length of time between refuelling is long, such as for mining haul trucks and long haul trucks respectively, an investment in LNG could be worthwhile.
Box 6: Shell’s LNG bunkering vessel at the port of Rotterdam.
Designed to provide fuel for LNG powered ships bunkered at the port of Rotterdam, Shell’s soon to be completed LNG refuelling vessel will be able to carry 6,500 cubic metres of LNG and be sufficiently manoeuvrable to re-fuel a wide variety of vessels. The vessel will use cutting-edge technology to supply LNG for large container ships as well as coastal vessels and ferries, and is designed with an on-board sub-cooling unit to keep the fuel at sub-atmospheric pressure. This follows Shell’s investment to support the world’s first 100 percent LNG powered barges carrying goods on the River Rhine – Greenstream and Green Rhine.64 64 Company website; interviews with Shell employees.
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The role of natural gas in Australia’s future energy mix
Switch to LNG for rail Outside Australia’s major cities, locomotives are often run on diesel. This is especially true of the approximately 1,500 locomotive engines serving iron ore and coal mines around the country. Converting 750 of these engines to run on LNG rather than diesel has the potential to save up to US$100 million per year in fuel costs, while at the same time abating 0.2 million tonnes of CO2-e. The technology for utilising LNG in rail is relatively new, with only a few trials so far. Despite this, the potential savings warrant it worthy of further investigation. Using LNG to power mining freight trains may also have a potential infrastructure cost synergy with switching mining haul trucks to LNG, as energy could be supplied for both purposes from one LNG liquefaction facility.
Switching oil-fired power generation to gas could reduce fuel costs Off-grid generation Off-grid oil-fired power generation is used for captive generation in remote mining and industrial facilities. In a business-as-usual scenario oil is expected to supply about 20 percent of off-grid electricity, or 3.4 terawatt-hours in 2030. Oil fired power generation capacity could be replaced by robust gas technology (OCGT), which could reduce the SRMC of generation by around US$90 per megawatt-hour. Switching off-grid generation to gas would require retrofitting generators to gas turbines at an annualised cost of around US$18 million. Also, diesel generators emit around one-third more CO2-e than equivalent open cycle gas turbines.65 Retrofitting diesel generators to run on gas could reduce emissions by up to 0.8 million tonnes of CO2-e per year, which equates to a saving of up to US$360 for every tonne of CO2-e abatement. Capturing this opportunity may depend on the availability of infrastructure for supplying gas to be used as fuel. If this infrastructure needs to be built, the cost of doing so may preclude some areas from converting to gas-fired generation.
On-grid generation Oil-fired power generation is used for supplying power to the grid during periods of peak demand. Switching to gas could lower fuel costs by around US$90 per megawatt-hour of electricity generation.66 Replacing diesel generators by increasing the utilisation of existing OCGT plants could reduce emissions by up to 0.2 million tonnes of CO2-e per year, which equates to a saving of up to US$380 for every tonne of CO2-e abatement (Exhibit 14).
65 0.85 tonnes of CO2-e per megawatt-hour for diesel compared with 0.37 tonnes of CO2e per megawatt-hour for gas. 66 Switching costs have not been considered as part of the analysis. The role of natural gas in Australia’s future energy mix
33
Exhibit 14
There are opportunities for gas in the power sector Assumptions NEM example
Impact of using natural gas in power
SRMC in 2030 US$ per MWh 173
50
84 17
Emission intensity tCO2e per MWh 0.94 0.62 0.37
Replace 100% of off-grid oil generation (3.4 TWh) with new off-grid OCGT
0.85
55 34
7.5
Incremental gas demand bcm
Change in cost2 US$ billions
Abatement costs US$/tCO2e
0.9
-0.3
-360
0.2
-0.1
-380
2.3
0.4
60
3.4
0.1
10
28 Total
CCGT OCGT Coal1
0.8
Replace 100% of on-grid oil generation (0.8 TWh) 0.2 with existing OCGT Replace 13 TWh of coal generation by increasing CCGT utilisation from 32% to 90%
Thermal efficiency Percent
36
Lever— assumption
2030 emission abatement MtCO2e
8.5
Oil
1 Weighted average of subcritical black coal, subcritical brown coal and supercritical black coal 2 No capacity payment is assumed SOURCE: Interviews with technical experts; Department of Resources, Energy and Tourism, A Cleaner Future for Power Stations, 2010
Increasing the utilisation of CCGT power generation could reduce emissions – at a cost Around 20 percent of Australia’s gas-fired power capacity use CCGT technology.67 These plants are projected to run about 32 percent of the time in 2030. Increasing this number to 90 percent would allow other generation capacity to be ramped down, or even retired. This increased utilisation should be enough to replace 13 terawatt-hours of coal-fired generation to the NEM and SWIS in 2030, and at the same time reduce CO2-e emissions by 7.5 million tonnes per year. Implementing this option would not require any additional capital investment – the gas plants have already been built (see Box 7). The higher cost of gas relative to coal means that electricity generated in this way is expected to be more expensive. The cost to society could be US$400 million per year in higher power generation costs. The cost per tonne of CO2-e abated is expected to be US$60.
Box 7: Gas generation in Australia.
Australia has 86 grid-connected gas-fired power plants, of which 49 are connected to the NEM and 13 are connected to the SWIS. These power stations generate around 51 terawatt-hours of electricity a year. But the average grid-connected gas power plant sits idle much of the time. This is because gas prices are usually higher than coal prices, which means that gas plants are more expensive to run than their coal counterparts if no CO2-e costs are taken into account. As a result, gas plants are often only switched on during times when there is a higher demand for electricity.
67 ACIL-Allen, Electricity Sector Emissions, 2013. 34
The role of natural gas in Australia’s future energy mix
If these options were adopted, natural gas would play a new role in Australia’s energy mix The options listed above have the potential to begin making a contribution to Australia’s economy and environment immediately. If some or all of these options were implemented gas would find itself playing a new role in Australia’s economy, one that is expanded beyond that expected in a business-as-usual scenario. As well as providing heat in the residential and commercial sector, and heat and feedstock for industrial sectors, gas would play a key role as a fuel for the transport sector. Additionally, increased use of gas for power could reduce emissions from the sector by displacing other, higher-emitting forms of generation. Implementing these opportunities would increase demand for gas by 7.1 billion cubic metres in 2030 (Exhibit 15). Exhibit 15 Incorporating the opportunities identified could lead to 50 billion cubic metres of gas demand by 2030 Billion cubic metres
Transport
Residential & commercial
Mining and oil and gas
Industry
1 36 0
5
0
6 -3
50 4
12
12
2
6
5
6 14
12
14
14
2014
43 0
7 4 3
Power
11 Power generation
Industry
LNG liquefaction
Residential and commercial
Transport
2030 Additional Business gas options -as-usual consumption
14
2030 gas demand including additional opportunities
SOURCE: Department of Industry, Innovation and Science, Australian Energy Statistics, 2015; Department of Industry, Innovation and Science, Electricity Generation Major Projects, 2015; Bureau of Resource and Energy Economics, Australian Energy Technology Assessment, 2012
The role of natural gas in Australia’s future energy mix
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The role of natural gas in Australia’s future energy mix
4. What would need to be done to make this happen? The oil and gas sector must help with the infrastructure transition if the expanded role for gas is to eventuate Australia faces many choices and trade-offs as it decides how to ensure its economy has access to affordable, reliable and sustainable energy. Given the longevity of many of the assets that create or consume energy, such as power plants and factories, the choices made now will shape energy costs and CO2-e emissions for decades. If all stakeholders engage in this debate constructively, and share facts and opinions openly, the nation will arrive at the best solution for supplying the country’s energy needs. This report contains a ‘deep dive’ into the role that gas could play in helping to meet Australia’s energy and emission reduction needs. Other options exist beyond those covered here. Below is an outline of what actions can be taken to determine whether the options explored in this report are the right ones for the nation’s future and, where they are the right options, what needs to happen to implement them.
Possible actions for the energy industry The oil and gas industry has a big stake in the Australian fuel supply mix. Actions that the industry might take to help inform decision making include: Share internal research into the costs and benefits of the options listed in this report, and any other options worthy of debate, with policy makers and wider public. Transparency and sharing of ideas will maximise the likelihood that the best opportunities are identified and debated. Sharing knowledge should ensure that investment occurs in the technology most suited to the opportunities available. Commit to build, or support other players to build the required infrastructure to realise opportunities where a chicken-and-egg dynamic exists, such as gas refuelling stations for transport. Where possible and within the boundaries of existing regulations, seek to align investments between players within the oil and gas industry, and between the industry and government. Doing this would spread the risks of investment and increase the likelihood of successful projects. Engage proactively with policy makers, equipment manufacturers and society to invest in the required technological, regulatory, and societal conditions for implementation of new ideas. Resolving the chicken-and-egg dilemma of natural gas refuelling infrastructure for transport, or determining whether the benefits of increasing utilisation of existing CCGT power plants are worth the cost requires cooperation across many stakeholders, each of whom brings a different skillset or knowledge base to the table. Consider taking a stake in building, owning or operating gas assets in the power, heat, and energy services sectors to tip the balance in favour of action.
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It will take coordination and cooperation between industry, policy makers and regulators to ensure that opportunities which are beneficial for society and the economy are realised. The benefits of doing so are potentially large, both in terms of cost and emissions abatement potential. But these options should not be implemented without further analysis and robust debate. If there isn’t a clear benefit to all parties, including society, the opportunities in this report should not be pursued. If there is a clear benefit, it’s in everyone’s interest to work together to realise it.
Avoid a lock-in Energy infrastructure has a long life. This means that once it is built, a poor choice of technology can lock society into a future it might not want. It also means that owners of these technologies are at risk of adverse changes to regulation, in addition to the ‘usual’ risks from commodity price fluctuations and changes in demand. The risk of lock-in can be mitigated by proactive coordination between government and industry. A less strategic approach is more likely to lead either to lock-in, or to a situation where energy supply is less reliable, more costly, or more emissions intensive than is desirable.
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The role of natural gas in Australia’s future energy mix
The role of natural gas in Australia’s future energy mix
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Train 2 starts up, Curtis LNG. Image courtesy of BG Group Queenland.
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The role of natural gas in Australia’s future energy mix
Conclusion Australia’s final energy consumption is set to grow by 21 percent to 4,933 petajoules in 2030, driven by an expanding economy and a population that could top 30 million. At the same time, emissions targets are more ambitious than they have been in the past. A business-as-usual approach to energy supply suggests that the amount of renewables in the power sector would increase, while in other sectors the supply mix would remain largely unchanged. As a result, CO2-e emissions in 2030 would exceed COP 21 targets despite a 19 percent improvement in emissions intensity.68 In this scenario, the role of gas in Australia’s energy landscape in 2030 would remain similar to the role it plays today. It would continue to be used as a source of heat in the residential and commercial sectors, and as both heat and feedstock for industry. A large increase in gas consumption is expected to power Australia’s expanding LNG production. In the power sector, gas would continue to be used to supply power to the grid during periods of peak demand. However, increased generation from renewables and the lower cost of existing coal-fired generation mean that overall demand is expected to shrink. Overall, demand for gas is expected to increase from 36 billion cubic metres in 2014 to 43 billion cubic metres in 2030, which represents a slight increase in the share of overall energy supply from 24 percent to 25 percent. Many options exist that would divert Australia from the business-as-usual scenario, including the options involving natural gas that have been identified in this report. The options presented have the potential to lower total energy costs by US$0.9 billion annually by 2030, with the additional benefit of reducing CO2-e emissions by 10 million tonnes per year. If these options were implemented the role of gas would remain similar in the industrial, residential and commercial sectors. The transport sector would use an extra 3.7 billion cubic metres of gas, which is a significant increase from the 0.1 billion cubic metres used today. More gas would also be used for power generation than in a business-as-usual scenario, and the gas’ share of the overall fuel mix would increase to 29 percent. In the transport sector, switching to gas for road trucks (CNG or LNG); mining haul trucks, rail and shipping (all LNG); and buses (CNG) would result in total savings of US$1 billion annually by 2030. There would also be an emissions benefit. CO2-e emissions could reduce by 1.7 million tonnes annually in 2030. In the power sector, using gas instead of oil for supplying electricity during times of peak demand and for captive off-grid electricity generation could save a further US$400 million annually by 2030, while at the same time reducing CO2-e emissions by one million tonnes per year. Some of these options may turn out to not be worth pursuing – additional infrastructure would be required to supply remote areas with gas. This may limit the scope of the opportunity to locations where a critical mass of captive off-grid generation justifies the cost of building it.
68 The analysis presented in this report does not consider the impact of the Emissions Reduction Fund or emissions reduction policies other that the RET on Australia’s overall CO2-e emissions. The role of natural gas in Australia’s future energy mix
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Increasing the utilisation of existing efficient gas plants (CCGTs) in the power system, at the expense of more CO2-e emissions-intensive technologies could reduce CO2-e emissions at a cost of US$60 per tonne of abatement. While this option comes at a cost, it could be worth considering as part of the overall approach to further reduce carbon emissions in the economy. These opportunities will not be captured automatically. Shifting the fuel mix to natural gas will require new infrastructure, especially in transport. The oil and gas industry, together with the power and transport industries, must jointly muster the required will and capital to invest. The reward is the potential dual payoff of a stronger economy driven by a lower cost fuel mix, alongside lower CO2-e emissions.
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The role of natural gas in Australia’s future energy mix
Appendices Appendix 1: Modelling methodology and assumptions Overview of modelling approach The analysis in this report was conducted using analytics and modelling expertise from McKinsey’s Energy Insights team, using data and assumptions gathered from various external sources, and proprietary insights from the firm’s experts. Australian Energy Statistics 2015 from the Bureau of Resources and Energy Economics has been used for historical data as far as possible, as this source forms the basis for Australia’s international energy reporting obligations. Likewise, Australian Energy Projections to 2049-50, also published by the Bureau of Resources and Energy Economics, has been referred to for an external perspective of Australia’s final energy consumption in 2030. Reports and data from the Australian Energy Market Operator (AEMO) and Independent Market Operator (IMO) have been helpful for understanding power and gas markets in eastern and south-western Australia respectively. Insights were derived from two models provided by McKinsey’s Energy Insights team; our Global Energy Perspectives (GEP) model was used to project final energy consumption and the likely fuel supply mix to 2030. This was augmented with a bespoke model of power generation in the NEM and SWIS.69
Global Energy Perspectives energy consumption and fuel supply model The GEP energy consumption and fuel supply model is a bottom-up model based on research conducted by our Energy Insights team. It models energy consumption at the subsector level and then aggregates this to give a view of consumption and supply by sector.
Transport Light vehicles: Projected energy consumption for light vehicles is calculated based on a cross-sectional logarithmic regression of car penetration per capita for more than 100 countries. Fuel consumption in each year is derived from the total size of the car fleet, and varies in terms of vehicle size and powertrain. Perspectives on these trends are provided by McKinsey’s Automotive and Assembly Practice and based on expectations around the pace of technology development, such as electric vehicles, as well as the impact of vehicle emissions policies. Heavy vehicles: Heavy vehicles such as trucks are primarily used for freight transport. Tonne kilometres per capita are the primary driver of energy consumption in this sub-sector and are highly correlated to GDP per capita. Projections of energy efficiency improvement and fuelswitching are provided by McKinsey’s Automotive and Assembly Practice, based on the cost of infrastructure development to support alternative powertrains such as natural gas. Aviation: Energy consumption in aviation is driven by revenue passenger kilometres, which is a standard metric in the aviation industry. This metric has a high positive correlation with economic development. The industry standard for technical and operational efficiency improvement is set at 1.4 percent by the International Civil Aviation Organisation.
69 The power model also modelled remaining power generation as a third ‘grid’, although this accounts for only a small proportion of power consumed in Australia. The role of natural gas in Australia’s future energy mix
45
Residential and commercial Final consumption of energy in residential and commercial buildings is projected from a cross-sectional regression on the average energy consumption per capita against GDP per capita over the past three years for groups of countries classified based on average temperature range and variability throughout the year. Efficiencies are applied to factor in new building and appliance technologies. Expectations about insulation penetration and effectiveness, lighting and the energy efficiency of appliances are based on work by McKinsey’s Global Institute. The fuel supply mix is based on levels of urbanisation and building access to electricity and natural gas grids.
Chemicals Production of three basic chemicals are assumed to drive energy consumption from the chemicals sub-sector – organic chemicals, ammonia and chlorine. McKinsey’s Chemicals Practice projects production based on global demand and Australia’s cost of production and competitiveness in the global market. Energy intensity figures for each chemical production process are applied to determine overall energy consumption.
Iron and steel Energy consumption for the production of iron and steel is a function of Australia’s domestic iron and steel demand and the nation’s domestic steel production capacity. Demand is a function of the demand intensity curves as calculated by McKinsey’s Basic Materials Institute for 13 major regions globally. The fuel mix for steel-making plants is based on their furnace technology types.
Mining Projections of mineral production are used to determine the likely energy consumption from mining activity. The fuel mix is determined by expectations of fuel mix for mining vehicles, which is influenced by access to natural gas and projections of the adoption of natural gaspowered vehicles in mining.
LNG Energy demand for LNG trains is based on projections of future LNG production provided by McKinsey’s Energy Insights Global Gas Model. The energy intensity of each plant is calculated based on its construction date, which implies efficiency gains for newer plants.
Other industries Energy demand in other industries is based on historical regressions of each industry with GDP. Fuel mix is regressed over time to capture any changing trends in the mix between oil, gas, coal, renewables and others.
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The role of natural gas in Australia’s future energy mix
References In addition to input from McKinsey’s proprietary databases, functional practices and experts, the following references were used to inform the business-as-usual energy consumption and fuel supply scenario: AEMO, Gas Statement of Opportunities, 2016 AEMO, National Gas Forecasting Report, 2016 Australian Bureau of Statistics Australian Treasury, Intergenerational report, 2015 ClimateWorks, Pathways to Deep Decarbonisation in 2050, 2014 ClimateWorks, Industrial Energy Efficiency Data Analysis Project, 2013 Department of Industry, Innovation and Science, Australian Energy Statistics, 2015 Department of Infrastructure, Infrastructure and transport to 2030, 2014 Bureau of Resources and Energy Economics, Australian Energy Projections to 2049-50, 2014 IMO, Gas Statement of Opportunities, 2014
Australian power market model Analysis of the Australian power sector was conducted by separately modelling the National Electricity Market (NEM), South-West Interconnected System (SWIS) and the rest of the country.
Power demand The power demand projection was based on a bottom-up energy consumption forecast from the GEP model. Sent-out power was adjusted to total generation after factoring in selfconsumption by power plants, distributed and captive generation, and transmission and distribution losses. Load profiles were evaluated based on overall demand trends, sectoral shifts in the electricity consumption mix, and the impact of distributed generation.
Generation capacity The power supply mix was optimised by the model to satisfy total electricity demand, ensure sufficient capacity for peak-shaving, and minimise the total system cost. The capacity mix projection takes into account the retirement schedule of existing generators based on their economic lifetimes, the pipeline of new projects currently committed or under feasibility assessment, and capacity additions based on the expected LCOE of different technologies at the point in time when new capacity is needed. The shortto-medium term capacity projection is adjusted based on the progress of current projects, the views of McKinsey experts, and the LRET. Capacity additions post-2020 are driven
The role of natural gas in Australia’s future energy mix
47
by expectations of LCOE for various technologies. Constraints are added to the model to ensure projects meet minimum plant size per unit, and that renewables projects have sufficient resources such as wind and sun.
Generation dispatch Generation is dispatched according to the merit order of the short-run marginal cost (SRMC) of installed technologies. Each technology has an upper and lower bound utilisation based on technical constraints and resource availability. The model assumes that wind and solar generation are fully dispatched to encourage renewable project development (Exhibit 16). Exhibit 16
Capacity and generation mix is optimised to minimise the total cost Model driver
Renewables
Model constraint
Gas Coal Capacity, MW
To match capacity requirement and minimise total cost
Cost for capacity build
Constrained by ▪ Available resources ▪ Min. plant size Capital cost Long-run average cost
X
Fixed O&M cost LCOE
To match demand requirement and minimise total operating cost
Short-run marginal cost
Cost for generation
X
Short-run marginal cost
Fuel cost
Variable O&M cost
Carbon cost
Fuel cost
Carbon cost
Generation, TWh
48
Variable O&M cost
The role of natural gas in Australia’s future energy mix
To match peak load and base load separately
References In addition to input from McKinsey’s proprietary databases, functional practices and experts, the following references were used to inform the business-as-usual Australian power market scenario: ACIL-Allen, Electricity Sector Emissions, 2013 AEMO, National Electricity Forecasting Report, 2015 Australian Energy Regulator, Designated Generation Facilities, 2014 Clean Energy Regulator, Administrative Report and Annual Statement, 2015 Clean Energy Regulator, REC registry CSIRO, Australian electricity market analysis report to 2020 and 2030, 2014 Department of Environment, Australia’s 2030 Emissions Reduction Target, 2015 Department of Industry, Innovation and Science, Electricity Generation Major Projects, 2015 Department of Resources, Energy and Tourism, A Cleaner Future for Power Stations, 2010 Department of Resources, Energy and Tourism, Australian Energy Resource Assessment, 2010 Bureau of Resources and Energy Economics, Australian Energy Projections to 2049-50, 2014 Bureau of Resources and Energy Economics, Australian Energy Statistics, 2015 Bureau of Resources and Energy Economics, Australian Energy Technology Assessment, 2012 Bureau of Resources and Energy Economics, Australian Energy Technology Assessment, 2013 IMO, Electricity statement of opportunities, 2014
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Appendix 2: List of acronyms AEMO
Australian Energy Market Operator
APPEA
Australian Petroleum Production & Exploration Association
BAU Business-as-usual bcm
Billion cubic metres
CCGT
Combined cycle gas turbine
CNG
Compressed Natural Gas
COP 21
21st Conference of the Parties to the United Nations Framework Convention
FID
Final investment decision
GDP
Gross Domestic Product
GEP
Global Energy Perspectives
GW Gigawatt IMO
Independent Market Operator
LCOE
Levelised Cost of Electricity
LNG
Liquefied natural gas
LPG
Liquefied petroleum gas
LRET
Large-scale Renewable Energy Target
Mt CO2-e
Million tonnes of CO2 equivalent
MWh Megawatt-hours NEM
National Electricity Market
NGV
Natural gas vehicle
NTEN
Northern Territory Electricity Network
OCGT
Open cycle gas turbine
O&M
Operations and maintenance
PJ Petajoule PV Photovoltaic RET
Renewable Energy Target
SRMC
Short run marginal cost
SWIS
South West Interconnected System
TWh Terawatt-hours 50
The role of natural gas in Australia’s future energy mix
ABOUT MCKINSEY ENERGY INSIGHTS
Energy Insights provides insights across the entire energy value chain to help energy players make strategic decisions, identify areas for performance improvement, and capture value for each of their individual assets. Energy Insights combines McKinsey’s global energy expertise, proprietary data, tools, and a dedicated team of experts to deliver the custom information clients need for business planning and decision-making. An international team of Energy Insights specialists actively supported the preparation of this report, providing market analysis and energy modelling expertise.
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McKinsey Australia June 2016 Copyright © McKinsey & Company Design contact: New Media Australia www.mckinsey.com
