Appendix d progress towards Australia’s emissions reduction goals

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

	Historical		Projected
Fuel type	2000	2012	2020	2030
Coal (conventional)	83%	71%	48–67%	9–70%
Natural gas (conventional)	8%	15%	9–25%	8–14%
Coal and gas with CCS	Not available	Not available	Not available	Up to 7% Potentially deployed as early as 2030 but as late as mid 2040s
All renewable	9%	11%	21–24%	21–69%
Solar	Negligible	1%	3%	6–14%
Wind	Negligible	3%	11–12%	9–20%
Geothermal	Not available	Not available	Not available	Up to 28%

Note: Results are based on shares of generation ‘as generated’ for four modelled scenarios with various levels of price incentive, as described in Chapter 9. All scenarios include the RET as legislated. ‘All renewables’ includes hydro, wind, geothermal, biomass, solar PV and solar thermal. Solar water heating is not included.
Source: ACIL Allen Consulting 2013

Off-grid electricity generation, which is generally in regional and remote areas, has a different supply mix. Its emissions intensity is currently lower than for Australia’s as a whole. In 2012, almost 80 per cent of off-grid generation was produced using gas, reflecting the high proportion of energy and resource operations located in areas supplied by gas pipelines (BREE 2013c). Indications are that gas generation will continue to dominate off-grid electricity generation (ACIL Allen Consulting 2013).

Compared with the national average of almost 10 per cent, the share of renewables in off-grid generation was as little as 2 per cent, with the greatest share in the southern states. In Tasmania, New South Wales, Victoria and the Australian Capital Territory, renewables account for 27 per cent of off-grid generation (BREE 2013c, p. 19).

D3.2.3 Drivers of emissions intensity of generation

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

Multiple drivers change the business cases of electricity generation projects. Modelling suggests that policy is a critical influence. The presence of a price incentive for emissions reduction, and the level of that incentive, can make different sources more or less competitive. This is evident from the greater share of low-emissions generation in scenarios with a higher price incentive. The effect of the RET, which provides an additional revenue stream to support the deployment of renewable sources, is also apparent to the 2020s. If the RET was reduced or not met, the emissions intensity of generation would be higher than that projected here.

Other drivers include exchange rates, commodity prices, interest rates, and rates of deployment and learning. In the near term, the levelised cost of electricity (LCOE) from different technologies will also be driven by fuel costs and the value of RET certificates. Given uncertainties about these many drivers, there is a range of estimates about costs of future generation. Figure D.14 reflects one view from the Bureau of Resource and Energy Economics (BREE 2012). In its 2013 AETA Update, BREE revises down its estimates for LCOE for renewable generation, particularly post-2030. The projected improvement in cost is especially significant for solar thermal, even without a price incentive (BREE 2013d, p. 62).

Figure D.14: Projected cost of selected generation technologies (with a carbon price), in 2020, 2030 and 2040

 

Notes: Assumes a price incentive around the levels in the Treasury and DIICCSRTE’s 2013 medium scenario. Solar thermal is compact linear Fresnel reflector (CLFR) without storage; solar PV is fixed (no tracking). Brown coal prices are for Vic.; black coal, gas, wind and solar are for NSW; geothermal is in SA.

Source: ACIL Allen Consulting 2013 medium scenario (‘central scenario’) (for NEM prices); BREE 2012 (for LCOE)

To at least 2020, relatively stable demand for grid-connected electricity makes it unlikely that there will be significant investment in electricity generation, except in response to policy drivers such as the RET (AEMO 2013g). During this period, existing generators, which have already amortised their initial capital investment, will be likely to continue to operate. This means that the risk of ‘lock-in’ of new high-emissions generation is relatively low for the next 10 years.

Longer term, as economic activity grows and electricity demand rises, new generation will be needed. Capital and regulatory hurdles aside, lower cost generation sources will be taken up more quickly and deployed more widely. Given the long operating life of electricity generators, future fleet investment choices are likely to influence Australia’s emissions for decades. Investment plans of major energy sector players, however, suggest building new emissions-intensive coal-fired plants is unlikely (see, for example, AGL 2013, pp. 37–8).

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

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