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Integrating climate and energy policy – investing in modern, low-emissions generation to deliver energy security

Andy Vesey
Andy Vesey
05 October 2016
By Andy Vesey - Managing Director & CEO,  AGL Energy Limited

Integrating climate and energy policy – investing in modern, low-emissions generation to deliver energy security

The recent state-wide loss of electricity in South Australia has resulted in a significant amount of discussion about energy policy settings. Hopefully, it will provide a catalyst for reforms which many (myself included) believe are long overdue. Most importantly, policy makers need to better integrate the three key, but sometimes competing objectives: competitiveness; energy security and decarbonisation.

The National Electricity Market (NEM) was created in the 1990s as an ‘energy-only’ market. Electricity generators are paid for the ‘energy’ they produce but not the reliable ‘capacity’ they make available. When the market was created, very few stakeholders envisaged the need to accommodate ‘intermittent’ renewable generation. At the turn of the century, things began to change. Concerns about climate change resulted in a number of policies being introduced to incentivise investment in new renewable electricity generation capacity. The 20% Renewable Energy Target (RET) and various state government Premium Feed-in Tariff (PFiT) policies resulted in relatively rapid investment in renewable generation. But almost no attention was paid to the interaction of these climate change policy decisions with the ‘energy-only’ NEM electricity market design. Today, we need to consider both the physical and the financial integration of renewables into the NEM.

Refreshing the capital stock – creating a modern, secure and decarbonised energy system

There has been significant investment in new electricity generation capacity since the NEM was created in the 1990s. However, most of this investment has been driven by climate change and renewable policies rather than NEM wholesale market pricing. Electricity demand has also fallen relative to expectations. These factors have led to wholesale market pricing being insufficient to recover the long-run marginal costs of an ‘optimal plant mix’ (i.e. the optimal generation fleet for meeting demand).

In theory, ageing emissions intensive power stations that are surplus to requirements should be permanently retired and decommissioned. However, there are four potential barriers to exit for incumbent power stations that impact on decision making. Firstly, existing plant have very low economic costs (i.e. sunk costs) and so are likely to ‘sweat’ assets until the marginal cost of operations exceeds revenues obtained from reduced operation. Secondly, participants have a disincentive to exit due to ‘first-mover disadvantage’.  Thirdly, site remediation costs are often significant and deferring closure reduces costs by putting them off into the future.  Finally, policy uncertainty (which has been a significant feature of Australian energy markets in recent years) impacts on decision making.

Around three-quarters of the NEM’s thermal (coal and gas) plant are older than their original design life. These plants will need to be replaced with low emissions capacity (such as renewables, gas and advanced batteries) over the coming decades to ensure that system reliability is maintained. However, potential barriers to exit and relatively stagnant electricity demand have consistently supressed wholesale electricity revenues below the level required for new investment. This is a problem for investment in both renewable and complementary capacity (e.g. open-cycle gas turbines, pumped storage and advanced batteries). If we don’t update the electricity market architecture, renewable generators will be overwhelmingly reliant upon policy-based subsidies rather than market revenue. This future deters any new investment, raising costs and risking system security unnecessarily as the NEM increasingly relies on ageing, legacy plant. It is also a major deterrent for new investment.

Eventually ageing emissions intensive power stations will close. However, due to the lumpy nature of capital investment and the likelihood closure announcements will be made in a way that does not allow new capacity to be constructed before closure occurs, infrastructure failure due to age and insufficient maintenance spending becomes not just a possibility, but a reality.

We have seen this scenario play out in South Australia with this year’s unanticipated closure of the Northern Power Station and mothballing of Pelican Point Power Station.

There is a role for governments to establish policy that facilitates ‘orderly’ rather than ‘disorderly’ exit of emissions intensive aged power stations. Such policy could be based upon age (e.g. Canadian rule which requires power stations to be closed or retrofitted with carbon capture and storage when they turn 50), emissions intensity or a market mechanism (as proposed by Jotzo and Mazouz). Ultimately, policy makers should view such a closure policy as not only an important means of securing energy supplies from modern generation equipment; but also an effective way of systemically reducing greenhouse gas emissions and providing communities the certainty they deserve to plan for such a transition.

‘Energy-only’ markets and pricing volatility

Pricing volatility is effectively the economic means by which ‘energy-only’ markets provide revenue adequacy for an ‘optimal’ generation mix. Heavy fixed costs associated with building power stations are recovered at times of peak electricity demand. But with the introduction of very low short-run cost renewable generation (i.e. the sun and wind are free) via climate-related public policies such as the 20% Renewable Energy Target, pricing volatility must become extreme to ensure capital costs of the dispatchable, complementary thermal generation or battery storage technologies can be recovered.

A 2016 study[1] found that the NEM would require a market price cap of between $60,000 to $80,000 per MWh for revenue adequacy if the system was supplied by 100% renewable energy – six times higher than today. Prices would need to be able to increase by a factor of around 1,500 in half-an-hour. AGL estimates that the ratio of high to low wholesale electricity prices will increase by a factor of three if the Commonwealth Government’s emissions reduction target of 26-28% of 2005 levels by 2030 is to be achieved and the NEM market rules are not updated.

The ‘energy only’ market’s operation has effectively been altered through the implementation of legitimate climate change and renewables policies. Policy makers should therefore consider how the impacts of these policies can best be mitigated.

Firstly, a closure style policy for incumbent generation will provide investors with confidence that government policies will not result in significant oversupply and disorderly supply shocks.

Secondly, policy makers could increase security by incentivising renewable generators to partner with complementary ‘firm’ capacity (such as open-cycle gas turbines, pumped hydro or advanced batteries). Renewable obligations, such as the RET, could be redesigned post-2020 to require renewable projects to contract with complementary services to become ‘virtual’ power plants that provide firm low-emissions ‘baseload’ generation.

Thirdly, a glide path to a low-carbon future can be integrated into the existing wholesale electricity market through a baseline and credit emissions intensity trading scheme.

So what should the COAG Energy Council do?

Both sides of politics, the States and the Commonwealth need to re-establish confidence in government policy.

The Commonwealth is right to suggest that energy security has not been given the policy attention it deserves. The States are also right to suggest that action beyond the RET is required given the scale of the climate challenge we face.

As we look beyond the RET, we need to map a pathway to a net zero electricity system by 2050. This will require dispatchable renewable energy. We should start now by requiring renewables to partner with gas, hydro or advanced batteries to be dispatchable in the same way fossil fuel plant is.

It would be unfortunate if simple ‘one-off’ interconnection investments are thought to be capable of delivering energy security in the long-run. While interconnection should be considered, it will not improve energy security unless the generation stock is modernised. Furthermore, communities may become more ‘energy self-sufficient’ through the use of embedded generation and storage, negating the need for growth in large interconnected transmission systems.

There are three main policies that require attention.

  • Ensure that the transition to a modern, secure and low-emissions electricity system occurs in an ‘orderly’ rather than ‘disorderly’ way. A policy framework that ensures the orderly retirement of ageing emissions intensive power stations is required. Such a policy will enhance energy security by bringing forward the necessary investment in new generation, both renewable and complimentary conventional assets. An old infrastructure is a much less secure infrastructure. A closure rule has precedent given the existence of age based limitations on power station operations in Canada and other jurisdictions.
  • Revisit the design of complementary policies to the NEM. ‘Energy-only’ markets require extreme pricing volatility to produce adequate revenues to incentivise new investment in renewables and complementary capacity (e.g. open-cycle gas turbines or advanced batteries). Renewable policy frameworks should evolve to creating ‘virtual’ firm low-emissions ‘baseload’ generation.
  • Establish a market architecture which sets a glide path to a low-carbon electricity systems. A baseline and credit emissions intensity trading scheme is a low cost tool which would integrate emissions intensity into the wholesale electricity price.

It is the combination of these policies that is required to provide the necessary framework for effectively addressing the concurrent challenges of decarbonisation and energy security.

Finally, renewables policies should be designed in a way which progressively decarbonises each State, rather than shifting all of the investment and impacts into one State (as has occurred in South Australia to date). No single state should do all of the heavy lifting, but the state targets need to be co-ordinated in a consistent way to ensure costs are minimised and shared fairly.

Over the remainder of the year, the COAG Energy Council will consider the policies required to better integrate renewable energy into our energy mix. As policy makers consider the 2017 Climate Policy review, a critical challenge is how to better integrate energy policy into Australia’s response to climate change. The two policy areas are as interconnected as our energy system.




[1] J. Riesz, J. Gilmore, I. MacGill (2016) “Assessing the viability of Energy-Only Markets with 100% Renewables – An Australian National Electricity Market Case Study“, Economics of Energy and Environmental Policy (EEEP), 5(1), p. 105-130.