By Tim Nelson, AGL Head of Economic Policy and Sustainability
The economics of electricity generation and carbon pricing
As a consequence of reliance on low-cost brown and black coal for the production of electricity, Australia’s greenhouse gas emissions intensity of 0.94 tonnes CO2e per MWh is significantly higher than many other countries. The incorporation of carbon pricing and renewable energy obligations into electricity generation investment decisions is likely to drive higher uptake of non-coal options over the coming decade.
Existing Australian electricity generation and emissions
Australia’s electricity consumption is predominantly fuelled by coal-fired generation. In 2010, about 81 per cent of Australian electricity generation used coal as its primary input fuel compared with 12 per cent for gas and 7 per cent for renewables. This is outlined in Table 1.
In New South Wales and Queensland, black coal-fired power stations have emissions intensities between 0.8 and one tonnes CO2e per MWh. However, in Victoria, brown-coal fired power stations have an emissions intensity of between 1.25 and 1.55 tonnes CO2e per MWh. As a result of these intensities and the mix of energy outlined in Table 1, the average intensity of the National Electricity Market (NEM) in Australia is currently about 0.94 tonnes CO2e per MWh. Simshauser and Doan (2009) noted that this is substantially above the European average of 0.35 tonnes CO2e per MWh.
Table 2 presents the emissions factor and generation output for each individual region of the NEM. The intensities largely reflect the predominant technologies of the individual regions. The lower intensities of South Australia and Tasmania reflect the higher proportion of renewables (zero-emission technologies).
Options for new electricity generation investment
Prior to considering the impacts of a carbon price on new investment decision-making, it is worth noting the unique characteristics of electricity markets:
• Generation plant with relatively high capital costs but low operating costs is used to meet baseload demand (demand that occurs for most of the time). Historically, black and brown coal generation, which is slow to start or shut down, has been used to meet baseload demand and such plant typically operates at a 75-90 per cent annual capacity factor.
• Intermediate demand (nominally the higher daytime demand) is generally met by plant with medium capital and operating costs and flexible operating capacity (i.e. can be ramped up quickly). Combined cycle gas turbines and aging thermal plant are generally used to meet intermediate demand and typically runs at annual capacity factors of between 40-60 per cent.
• Generation plant with relatively low capital costs but high operating costs is used to meet peak demand (demand that only occurs on the hottest and coldest days of the year, or during power system contingency conditions). Open-cycle gas turbines or hydro generation (pre-existing capacity built by governments), which can be ramped up very quickly, is generally used to meet peak demand and typically operate at annual capacity factors of between five to 30 per cent.
Figure 1 outlines the long-run marginal cost (LRMC) and emissions intensities of electricity generation technologies. It is clear from Figure 1 that black coal and brown coal technologies are preferred where carbon prices are not incurred. However, these technologies have relatively high-emissions intensities (0.8 and 1.1 tonnes of CO2e per MWh). Combined cycle gas turbines are have slightly higher costs but have an emissions intensity only half that of black coal (around 0.4 tonnes per MWh). Zero emission technologies have higher costs and are generally non-firm in nature. This is due to the intermittancy associated with renewable energy (i.e. the wind is not always blowing and the sun is not always shining).
The impacts of the Renewable Energy Target
The primary driver of new investment in generation capacity over the coming decade is likely to be the Large Scale Renewable Energy Target (LRET). The legislation underpinning the target requires retailers to purchase 41,000 GWh of new renewable energy by 2020. Modelling completed by AGL in 2010 showed that around 9000 MW of new renewable energy capacity would be required by 2020 to fulfil this obligation (AGL, 2010). Based upon the costs presented in Figure 1, it is expected that a significant proportion of the LRET will be met by constructing wind farms.
The Economics of a Carbon Price on LRMC
To assess how a carbon price impacts on the long-run marginal cost of electricity generation technologies, carbon prices are plotted against LRMC in Figure 2. This diagrammatic representation is colloquially known as the ‘pick-up sticks’ graph.
The pick-up sticks diagram allows an investor to determine the carbon price that would be required to alter an investment decision from one technology to another. Based upon LRMC estimates from Nelson et al (2010) for black coal, CCGT and wind of $50/MWh, $58/MWh and $120/MWh respectively, it is clear that a carbon price of around $20 per tonne would result in the displacement of new coal for new gas. However, a carbon price of around $90 per tonne would be required to displace new coal for new wind. Caution needs to be exercised in drawing too many conclusions from such simple analysis. As outlined previously, the electricity market is unique in that supply must equal demand at all times because electricity cannot be stored economically. Accordingly, the economics of technologies for meeting variable demand and their carbon intensity both need to be considered in any analysis of the optimal technology to be invested in.
Putting a Carbon Price in Perspective
This analysis has demonstrated how a carbon price of around $20 per tonne could result in displacement of new coal for new gas fired electricity generation. In the short-term a price increase of $20 per tonne is likely to result in uplift in wholesale electricity prices of around $20 MWh. Such price increases also need to be put into perspective. A recent study by Nelson et al (2010) demonstrated that the costs of uncertainty in relation to inaction on climate change policy is likely to result in electricity prices increasing by around $8.60 MWh more than necessary due to the introduction of a sub-optimal capital stock. Furthermore, Simshauser et al. (2010) forecast that electricity prices are likely to increase by around $140 MWh by 2015 due to higher network capital expenditure and commodity price increases.
Table 1: output and capacity of Australian electricity generators
|Type||Output (GWh)||% of Total||Capacity (MW)||% of Total|
|Source: Nelson et al (2010)|
Table 2: Emissions Factors for electricity production
|State||Emissions Factor (t/MWh)||Generation Output (TWh)|
|New South Wales and ACT||0.90||73.4|
|National Weighted Average||0.94|