In order to meet Australia’s 2030 emissions reduction target, a significant change in the operation of the electricity sector will be required, driving the decarbonisation of the National Electricity Market (NEM). While bi-partisan support exists for the review of Australia’s 2030 emissions reduction target every five years, the major political parties remain divided on the best policy approach to achieve longer term emissions cuts. The government is committed to its Emissions Reduction Fund (ERF), and the Large-scale Renewable Energy Target (RET), with a review of its Direct Action Plan policy to take place in 2017-18. In parallel, the Australian Labor Party (ALP) has stated that it intends to re-introduce an electricity-generation emissions trading scheme (ETS) as it seeks to achieve a 50 per cent renewable energy goal by 2030.
In order to support a market-based transition away from emissions intensive generation, a number of policy recommendations have been publicly tabled by academics and market observers. Policy recommendations have broadly taken two forms – proposals for the orderly exit of highly emissions intensive power stations from the NEM – as put forward by Frank Jotzo and Salim Mazouz (Jotzo),[1] and more recently by The Climate Institute (TCI)[2] – or proposals for the long-term decarbonisation of the power sector via the creation of an emissions intensity baseline scheme, as put forward by the Australian Energy Market Commission (AEMC), and more recently by the Grattan Institute.
In theory, each proposal will deliver emissions reductions. In practice, however, political considerations – such as the impact of regulation on electricity prices, and the willingness of industry to embrace reform – will be critical barriers to the implementation of proposed policy.
In this context, we believe any practical form of lasting policy must balance both market and political considerations, by being designed to achieve a number of outcomes, including:
- Achieve large-scale emissions cuts in line with Australia’s 2030 emissions reduction target;
- Support the orderly exit of emissions intensive generation from the NEM, making room for new wind and solar generation;
- Minimise impacts on retail electricity prices; and
- Gain the support of industry, notably business associations, ‘gen-tailers,’ and the renewable energy sector.
While, in isolation, proposals from academics and market observers may be able to achieve one or more of the above objectives, in reality, there is no ‘silver bullet’, whereby one policy will be able to achieve all necessary outcomes. We therefore believe that a hybrid policy approach that combines components of these studies may be best suited to drive the decarbonisation of the electricity sector, while still meeting key political objectives.
While an orderly approach to retire emissions intensive generators, proposed by Jotzo and TCI, may regulate the exit of brown coal generation and accelerate the decarbonisation of electricity generation, in isolation, such an approach is unlikely to be a long-term framework to govern power sector emissions in line with Australia’s 2030 target. Inversely, the introduction of more ambitious emissions intensity baseline scheme (or ETS), as proposed by the AEMC and the Grattan Institute, is unlikely to support the short term exit of emissions intensive generators unless strong baselines are adopted early in the scheme, which is politically infeasible.
In this context, we see scope for the development of a ‘soft start’ ETS framework prior to 2020 to establish the architecture for a more ambitious trading scheme after 2020, in line with Australia’s long-term emissions reduction target(s). This may establish separate schemes for the power and industrial sectors, facilitating a two-speed market to achieve various policy outcomes via different caps and targets, compensation and access to offsets. In parallel, there is pressure to take more immediate action to begin the decarbonisation of the electricity sector by establishing a framework to kick-start the closure of older, heavier polluting generators in an orderly process. We believe an industry-funded auction mechanism, similar to that proposed by Jotzo and Mazouz, may appeal to the market by providing an incentive to retire a large emissions intensive generator. In contrast, proposals which call for the eventual closure of all coal-fired generators through age-limited regulation, without providing payments, are unlikely to receive wider industry support and are therefore unlikely to be politically achievable.
Despite the political and market draw of Jotzo’s proposed mechanism, limited analysis has been undertaken on the impact of the proposal on retail and wholesale electricity prices, with Jotzo’s paper exploring the issues theoretically, providing empirical illustrations, without modelling the operation of the NEM (which was outside the scope of his analysis).
In this Market Update, we take a detailed look at Jotzo’s proposed market mechanism for the regulated exit of highly emissions intensive power stations from the electricity grid, and analyse the impact on the NEM in terms of emissions reductions and electricity price implications.
Analysis indicates that the removal of a single emissions intensive generator may occur with relatively minor wholesale price impacts. Moreover, analysis of retail price trends indicate that Australia currently has a unique window to implement electricity market reform with little impact on retail electricity prices. This is due to the likelihood of stable medium term retail prices as a result of broader market factors – including moderating consumption, more renewable energy, and network revenue determinations . Subsequently, the exit of a brown coal-fired generation may be implemented to have a negligible effect on electricity bills.
RepuTex modelling approach
To explore in more detail what the emissions intensity of the replacement electricity may be, we have utilised our NEM Generation Model, which replicates the NEM’s competitive least cost dispatch process for each of the supply and demand conditions in the forecast periods, modelling the resulting generation and emissions from each of the scheduled generation plants.
The competitive bidding model constructs the default four price and quantity pairs. All price and quantity pairs are in percentage of the cost and available capacity of each plant except the price in the first band, which is fixed at $0/MWh. The first band of a bid applies to plant-level minimum generation. The second band applies to short-run marginal cost and the third to long-run marginal cost. The last band applies to the market’s ceiling value of lost load (VOLL).
