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There's a better way to manage coal closures than paying to delay them

September 16, 2021
Johanna Bowyer and Tristan Edis
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Key Findings

The Energy Security Board is absolutely correct in identifying that the financial viability of a number of coal-fired power plants are under threat due to an influx of wind and solar.

The Energy Security Board is correct that for power reliability to be maintained with the exit of coal power stations, there is a need for solar and wind to be complemented with technologies which can vary their output up and down on command - that are “dispatchable”.

The Energy Security Board has correctly identified key ailments facing the National Electricity Market. The capacity mechanism does not address these ailments.

Executive Summary

This report has been produced in response to a recommendation flowing from the Energy Security Board’s post-2025 market design review. This review investigated whether the market design for the east coast main electricity grid (known as the National Electricity Market or NEM) was appropriately structured given expected substantial changes in the future electricity supply mix.

This capacity market mechanism should be rejected by state government energy ministers.

This report focuses in on one recommendation strongly backed by the Federal Energy Minister Angus Taylor for the introduction of a capacity market into the NEM, which is currently an energy-only market. Our analysis suggests that this capacity market mechanism should be rejected by state government energy ministers, as there are better options available to address challenges facing the NEM which have been identified in the ESB’s review.

Under the current energy-only market design, electricity generators are only compensated by the energy market operator for the megawatt-hours of electricity they deliver to the grid and market customers only pay for the megawatt-hours of electricity they consume. Under the ESB’s proposal this would continue, but in addition market customers would need to also pay generators for capacity credits. The credits would be awarded to a generator based not on the electricity they actually produced but rather an assessment of the maximum electricity they could potentially produce during periods of time that energy officials considered to face risks of supply outages (black-outs). By definition these would be periods when wind and solar generation was low so these plants would be largely excluded from qualifying for capacity credits.

The Energy Security Board proposes to develop the detailed design of the capacity mechanism over the next 12-18 months, with the starting point for the design work being what they have entitled a Physical Retailer Reliability Obligation proposal.

In this report, we have chosen to evaluate this proposal for a PRRO capacity market based on an assessment as to how well it helps address a series of problems or ailments that the Energy Security Board themselves have indicated afflict the National Electricity Market. For the most part we believe the ailments identified by the Energy Security Board are valid and act to deter private sector participants on their own initiative and without support from governments from making timely investments that would ensuring the adequate supply of electricity to ensure reliability. In addition to evaluating the ESB’s proposed remedy we examine various alternative policy options to deal with each of the ailments.

Throughout the post 2025 market design process, the ESB has done a good job of highlighting key challenges facing the National Electricity Market. The ailments they identify as inhibiting timely investment in supply to ensure reliability mainly revolve around: a) high levels of uncertainty around coal exits; b) myopic market contracting behaviour; c) early mover disadvantage in power technologies subject to cost deflation; and d) unpredictable government intervention.

Recent reports IEEFA have written on this topic have come to the following conclusions.

  1. The financial viability of several coal generators is under threat, such that there is a risk of abrupt, unexpected closure. It is vital to manage coal exit uncertainty.
  2. There is a large amount of dispatchable capacity coming online, which buys energy planners time to manage the exit of coal generators in an effective manner without threatening reliability. 
  3. The Energy Security Board capacity mechanism proposal has the potential to impose a substantial additional costs on electricity consumers; with experience from Western Australia’s capacity market indicative of annual payments between $2.9billion to $6.9 billion a year. This would be allocated primarily to existing conventional generators, and would exacerbate uncertainty rather than reduce it.
  4. The Energy Security Board’s own capacity market benefit calculation cannot be relied upon to provide a full picture of the costs and benefits of the capacity mechanism.

From these previous reports, is clear that such a massive change to the National Electricity Market, involving a new, perpetual multibillion dollar annual payment given to primarily conventional generators is not justified, nor justifiable, on a cost-benefit basis. It is also clear that a capacity mechanism will not address the investment uncertainty challenge that the National Electricity Market currently faces.

We find that the capacity mechanism does not address the ailments facing the National Electricity Market as it will increase uncertainty around coal exit.

In this report, we find that the capacity mechanism does not address the ailments facing the National Electricity Market, as it will increase uncertainty around coal exit, will not increase the duration of contracting, does nothing to combat first mover disadvantage and does not address the underlying reasons for why governments are regularly intervening in the electricity market.

Energy ministers should instead consider a combination of the following measures as a starting point, which could be further developed and evaluated by a genuinely independent panel of energy market and decarbonisation technology experts:

  • A strengthened regulatory regime for ensuring owners of large and aged power stations give at least three and half years notice of exit based on providing an upfront bond rather than depending on application of penalties only once a breach occurs (which is the current case). This should be complemented by the use of financial and engineering audits every three years of these large, aged power stations to undertake stress-tests of their ability to maintain reliable operation and their risk of abrupt exit.
  • Enact legislation that sets out a schedule for coal generating units to be steadily retired once set amounts of new reliable replacement capacity are built. This will give investors in new capacity enhanced clarity and incentive to build new plant but such investments will be primarily guided by expected returns in the electricity market, and should allow investors wide discretion on the plant technology that best suits market needs. The specific order in which coal units are retired can be determined through an array of different alternative methods which could include: voluntary nomination by owners (likely if plant is loss making and notice period bond is returned); an auction process where units are paid to retire; or regulatory criteria (e.g. evaluation of their relative reliability or unplanned outage risk; emissions intensity, age).
  • Provide a floor price underwriting mechanism to encourage new competitors that build new dispatchable capacity. This could be modelled along the lines of the ACCC’s 2018 electricity market reviewrecommendation where a new entrant would be expected to first secure a 3 year contract to provide firmed power supply to customers outside of the major government and private sector retailers. The price floor would then cover years four to seven of the plant’s life.
  • Implement the emissions obligation component of the National Energy Guarantee or an alternative, long term mandatory obligation for electricity retailers or generators to reduce emissions based on tradeable certificates. The emission target should be based on a steady reduction in annual emissions in line with States’ net zero by 2050 targets with interim targets reducing emissions well below an expected business as usual trajectory.
  • Contracts with individual generators to remain open as per the Victorian Government arrangement with Yallourn should be avoided. If such agreements are entered into they should include a schedule (detailed publicly) for faster retirement of generating units than agreed based on when suitable replacement capacity comes online. That replacement capacity should not need to come from the owner of the generator which is party to the support contract.
  • If merited based on an evaluation of the risk to reliability from abrupt coal exit in advance of completion of Snowy 2.0, augment the existing energy only market with enhanced energy reserve mechanisms.

Johanna Bowyer

Johanna Bowyer is the Lead Analyst for Australian Electricity at IEEFA. Her research is focused on trends in the National Electricity Market, energy policy and decarbonisation.

Prior to joining IEEFA, Johanna researched distribution networks at CSIRO, worked as an engineer at Solar Analytics and Suntech and worked as a management consultant at Kearney.

Johanna has a first-class Honours Degree in Photovoltaics and Solar Energy Engineering from UNSW Australia. While at UNSW she received the Co-op Scholarship, No Carbon Women in Solar Prize and Photovoltaics Thesis Prize.

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Tristan Edis

Tristan Edis is the Director - Analysis and Advisory at Green Energy Markets. Tristan’s involvement in the clean energy sector and related government climate change and energy policy issues began back in 2000. He has worked at the Australian Government’s Greenhouse Office, the Clean Energy Council; Ernst & Young, helped establish the energy research program at the Grattan Institute, and ran a website providing news and analysis on energy and carbon market issues called Climate Spectator.

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