(Updated July 2016)
- Australia is heavily dependent on coal for electricity, more so than any other developed country except Denmark and Greece. Three-quarters is derived from coal.
- Australia's electricity has been low-cost by world standards, but this has changed.
- Natural gas is increasingly used for electricity, especially in SA and WA.
- After many years of low investment, there is a major challenge to build more generating capacity.
- Domestic solar PV capacity is now over 4 GWe.
Electricity consumption in Australia has been growing at nearly double the rate of energy use overall. In 2013, about 10,700 kWh per capita was generated, including that incorporated into exports, with growth having levelled out for a decade, driven by price rises, due to network costs, and also in 2013-14 rooftop PV resulted in 2.9% reduction in grid supply. In 2013, final consumption was 8856 kWh per capita.
Electricity generation takes 42% of Australia's primary energy supply (in 2013), and in terms of final energy consumption, electricity accounts for 22% of the total.
Energy in Australia
Much of the energy exported from Australia is used for generating electricity overseas; three times as much thermal black coal is exported as is used in Australia, and all of the uranium production is exported.
Australia also exports a significant amount of energy in mineral products. Exports of aluminium metal* alone embed some 27 TWh of electricity per year, about 11% of the country's total gross production. Some 39 TWh is used in non-ferrous metals (aluminium smelter production uses 29 TWh/yr), over half of the industry total of 79 TWh in 2013.
Most of the growth in value-adding manufacturing in the past 20 years has come from industries which are energy- and particularly electricity-intensive. The growth has occurred in Australia because of relatively low electricity prices coupled with high reliability of supply and the proximity of natural resources such as bauxite/alumina.
In 2014 Australia's power stations produced 248 billion kilowatt hours (TWh) of electricity, 59% more than the 1990 level, but only 185 above 2000 level, and slightly less than in 2011 to 2013.
Of the gross amount of 249 TWh in 2013, about 16 TWh is used by the power stations themselves, leaving 233 TWh actually sent out (net production). Then about 15 TWh is lost or used in transmission and 12 more in energy sector consumption, leaving 206 TWh for final consumption (or 182 TWh apart from aluminium exports).*
In 2013 the electricity was produced from 64 gigawatts (GWe) capacity, of which 29.2 GWe was coal-fired, 18.7 GWe gas or multi-fuel, 1.35 GWe oil, 8.0 GWe hydro, 0.55 GWe biofuel, and 6.5 GWe other renewables.
Most of this is associated with the grid-connected National Electricity Market (NEM) in the southeast and east of the country (see below), the second grid being the South West Interconnected Supply area in Western Australia. A smaller grid is in the Pilbara.
In 2013, 69 TWh was from black coal, 92 TWh from brown coal, hence 64.65% was produced from coal, 53 TWh (21.3%) from natural gas, 18 TWh (7.2%) from hydro and 11 TWh (4.4%) from wind (IEA data).
In Victoria the main fuel is brown coal (lignite), in NSW and Queensland it is high quality black coal, and in WA and SA it is much lower quality black coal. Nationally in 2013, 25.6 Mt black coal (658 TJ) produced 68.6 TWh, while 87.9 Mt brown coal (1076 PJ) produced 92.2 TWh. For natural gas, 519.8 TJ produced 53.1 TWh (IEA data).
About 65% of Australia's electricity is produced from 48% of the capacity, reflecting the predominance of base-load demand and the fact that coal provides the main base-load capacity in Australia. See also chart below. Note that electrically, Western Australia is isolated.
National Electricity Market (NEM)
Eastern Australia's National Electricity Market (NEM) operates the world’s largest interconnected power system that runs for more than 5,000 kilometres from North Queensland to Tasmania and central South Australia, and supplies some $10 billion electricity annually to meet the demand of more than 10 million end users. The NEM volume-weighted average price in 2008-09 ranged from $36/MWh in Queensland to $49/MWh in Victoria and $69/MWh in SA. NEM infrastructure comprises both state and privately owned assets, and is managed under the overall direction of the Australian Energy Market Operator (AEMO), which was established by the state and federal governments.
In 2012-13 the NEM capacity was 48.4 GWe producing 204.5 TWh, 53% of this from black coal, 29% from brown coal, 7% from gas CCGT, 10% from hydro and 4% from wind. There were about 50 large dispatchable generators (100-750 MWe each), and they provided about 95% of the capacity. NEM capacity is 22.5 GWe coal, 9.5 GWe gas, 2.8 GWe wind, 7.9 GWe hydro, 2.0 GWe other.
The system load factor was about 55% and the reserve margin about 28%. In the competitive market the wholesale price averaged about $55/MWh. This comprised about 20% of final retail bills (51% being network, 20% being retail customer service and energy efficiency programs, and 9% being carbon price).
Unlike some overseas electricity markets where the transmission system operators activate dispatchable capacity 45 minutes ahead of perceived need, in Australia the NEM has real time balancing with the obligation on renewables up to five minutes before delivery. Prices are therefore capped very much higher, at $14,000/MWh. This has provided incentive for investment in new balancing plant, with 4 GWe of flexible capacity being added in recent years. In 2013 spikes went to $7000/MWh, with a lot above $1500/MWh. (In Germany the cap is €3000/MWh and the highest spike in 2013 was about €130/MWh, giving rise to little investment.) In Australia a gas-fired plant may only run for 900 hours per year (load factor 10%), on 1050 occasions, with 400 of the starts being for five minutes only, but it can be economic.
AEMO produced a National Transmission Network Development Plan (NTNDP) for 2030 which showed 251 TWh produced then in NEM – 62% black coal (27 TWh more than 2012), 17% brown coal (232 TWh less than 2012), 9% gas CCGT, 8% hydro and 17% wind.
South Australia's electricity
South Australia is small part of the NEM, but poorly connected, with a 460 MWe link to Victoria at Heywood (Vic) in the south and the 220 MWe Murraylink one further north, providing back-up from Victorian brown coal equivalent to about one-quarter of 3100 MWe peak demand. The Heywood interconnector is being upgraded to 650 MWe in both directions, at a cost of $108 million. Modelling by Deloitte Access Economics suggests that by 2019 the interconnectors from Victoria will be at maximum capacity into SA for about 23 hours per day. However AEMO forecasts a decline in supply from Victoria after 2020, due partly to Victoria’s greater reliance on wind, the output of which will fluctuate very much in line with that in SA.
The relatively dry and flat state has had a strong policy of promoting wind and solar capacity, and over 40% of its electricity is from these sources (from 1473 MWe wind, but no solar on grid). Gas accounts for 90% of the dispatchable supply (from 2617 MWe), and the former SA coal-fired plants have been shut down (Northern 546 MWe, Playford B 240 MWe). Another 3200 MWe of wind capacity is committed or proposed. Solar PV is widely used, but virtually all behind the meter.
As well as simply meeting power and supply demand, the challenge of power quality (voltage and frequency control) is increased by the high dependence on wind.
The outcome of this generation situation is that NEM spot prices are sometimes very high, when wind is low. The fossil fuel-fired power stations are uneconomic due to low capacity factors forced by significant priority input of wind generation, coupled with low prices in the wholesale market when (subsidised) wind is abundant. Several have therefore closed down, and a further 770 MWe of gas-fired plant is due to close in 2017. Gas prices are rising due to several factors, which acutely compounds the SA dilemma.
Following winter price spikes in 2015, AEMO commissioned a report by Frontier Economics, which said that the reason was a low level of wind generation at the time. “As has been long predicted, increasing penetration of wind, and its inherent intermittency, appears to be primarily responsible for the (price spike) events. While the events have coincided with relatively high demand conditions in South Australia and some minor restrictions on imports of electricity from Victoria, low wind production levels are the key common feature of every event. The market response at such times has been to offer higher-priced capacity to the market, leading to high prices, just as the National Electricity Market was designed to do under conditions of scarcity.”
The Frontier Economics report says the level of wind and solar penetration in South Australia presents a fascinating natural experiment in the impact of intermittent generation on wholesale prices. “Unfortunately, this test is anything but academic and the people of South Australia are increasingly likely to bear increased electricity costs as wind makes up a greater proportion of South Australian generation,” the report says. “While policymakers may be tempted to act to force thermal and/or wind to behave uneconomically, the likely outcome means South Australian consumers will bear more costs.” (From The Australian, 23/7/16)
In the first part of July 2016 prices averaged over $300/MWh in South Australia, compared with under $80/MWh in the four eastern states. In June, SA prices had averaged $133/MWh. Spikes of over $10,000/MWh have occurred. On 7 July, SA wind farms were producing 190 MWe early in the morning, but by afternoon they were actually drawing energy from the grid, this effect being most acute due to limited back-up supply.
There are proposals for three new interconnectors from SA to NSW, ranging in projected cost $3 to $3.75 billion, but none is proceeding. A further connection from Krongart in SA to Heywood (Vic) is projected at $530 million but is not proceeding.
The new federal minister for the combined portfolio of energy and environment, Josh Frydenberg, has said that it is clear the global energy supply dynamic was moving to lower emission energy sources. He said country comparisons showed that lowering emissions from the energy sector could not be one-dimensional because countries were starting from different positions and faced different challenges. “One such challenge will be the need to question traditional energy supply” and “such a discussion is currently taking place in South Australia,” he said, referring to the South Australian royal commission into the nuclear fuel cycle, which had “revived the discussion about the role nuclear power could play in a low-carbon economy. Given South Australia has 78% of Australia’s uranium reserves and the stable geology to store high-level waste, this debate is shifting community attitudes and has some way to run,” he said.
Australian Energy Technology Assessment (AETA)
The AETA was undertaken by the Bureau of Resources and Energy Economics (BREE) in 2012. It evaluated 40 utility-scale generation technologies, projecting out to 2050, and focusing on estimating the levelised cost of electricity (LCOE), using AEMO’s NTNDP parameters and those from Treasury. The capital costs of various options excluded financing and system costs. AETA assessed two nuclear technologies: large light water reactors and small modular light-water reactors (SMR). Capital costs used were $4210/kW and $7908/kW respectively for first of a kind units, and $3470/kW and $4778/kW for Nth of a kind (while noting that overnight costs in Asia are much lower). These gave almost the lowest cost ranges of any of the 40 technologies over 2020 to 2050, with GW-scale nuclear about $100-110/MWh and $115-125/MWh for SMR over 2020-2050.
This study complemented a CSIRO eFuture model, which shows that incorporating nuclear into the generation mix from 2025 so that it contributed about 55% of supply from 2040 would save $130 billion in greenhouse gas abatement and $18 billion in health cost savings to 2050 compared with the Government’s 2012 Energy White Paper projections, and reduce LCOE from $158 to $125/MWh over 2040-50. The retail price saving is $86/MWh. Looking at capital costs to 2050, the White Paper projects $195-225 billion, the eFuture with nuclear $175-235 billion, including $85-100 billion for nuclear build.
Australian coal is mostly very clean by world standards, so electricity is produced without very much sulfur dioxide being emitted (or requiring expensive equipment to avoid its emission).
However, power generation contributes 33% of the country's net carbon dioxide-equivalent emissions (179 out of 543 Mt in 2013-14). The 2008-09 figure calculated from thermal plants in an ESAA benchmarking study is 204 Mt, about 37% of total. In this, black coal plants in NSW emit 920,000 tonnes CO2 per TWh, Victorian brown coal plants emit 1.29 million tonnes CO2 per TWh.
The Cost of Electricity
Much electricity in Australia is now traded so that distribution companies buy at the best price available from hour to hour from competing generators. According to an informed estimate*, retail power prices comprise about 20% generation, 20% transmission, 20% retailer, and 40% distribution.
* Prof John Fletcher, UNSW
The difficulties matching supply with demand can be judged from the fact that Victorian demand ranges from 3900 MWe to 10,000 MWe, and that in NSW from 5800 to 15,000 MWe.
Australian electricity prices were almost the lowest in the world to about 2007, but have risen significantly since then, and international comparisons are exacerbated by the exchange rate. Hence 2011-12 average Australian household prices are above Japan and EU average and much higher than USA. By state, WA, Vic, NSW and SA 2011 prices rank behind only Denmark and Germany.
The earlier low prices created a major problem in attracting investment in new generating plant to cater for retiring old plant and meeting new demand – a 25% increase by 2020 was projected, and in fact a 40% rise occurred by 2011, with another 30% projected to 2013.
Australia has 27,640 km of transmission lines and cable (220 kV and above – 10,300 km 330 kV and above), mostly state-owned and operated, transporting 209 TWh of electricity per year (2008-09). There is no connection between the east of SA and WA.
Because most of Australia's electricity is produced near the main load centres there is less high voltage (500, 330, 275, 220 kV) transmission needed than in some countries. There is nearly as much at 132 kV as at those four higher levels combined. (At 500 kV, transmission losses over 500-1000 km are halved.)
OECD IEA, Electricity Information (to 2015).
ABARE, Australian Energy report 05.9
ESAA, Electricity Gas Australia 2010
AER Aug 2008, Network Report 2006-07
AGO 2004, Stationary Sector GHG Emission Projections
Vicpool Information Bulletin 3, 43.
CME report to Energy Users Association, March 2012, Electricity Prices in Australia: An International Comparison