Australia’s National Electricity Market (NEM) is rapidly evolving as solar and wind energy projects continue to enter the market at pace. The variability of production and lack of ‘firmness’ of renewable energy supply has left governments concerned about the ability of the NEM to deliver electricity to consumers reliably in the future.
The Federal Government tasked the Energy Security Board (ESB) with advising on a long-term, fit-for-purpose NEM design and the final advice around a market design to deliver for consumers was released last week by the Energy Ministers.
The ESB’s final report contained four key themes, one of which – resource adequacy as ageing thermal generation is retired – proposes the introduction of a certificate capacity mechanism. This raises various points of contention for the future of both the coal-fired and renewable energy industries.
Why is there a problem?
As the share of renewable energy in the NEM continues to grow, a challenging environment is emerging around the longevity of traditional energy production.
Coal-fired generators are struggling to maintain profitability and will continue to do so as renewable energy supply increases and captures more and more of the existing coal-fired generators’ market share.
Renewable energy advantages are well understood – the low marginal cost of production, zero-emissions supporting better outcomes for the environment and sourced from an almost endless supply base.
However, renewable energy production varies over the course of a day, as well as day by day, with variations in the wind and sunshine – and without additional ‘firming’ support – cannot provide a reliable supply for consumers.
Coal-fired power provides firm ‘dispatchable’ capacity and can provide a reliable supply to consumers but burning coal to produce electricity produces large volumes of carbon dioxide which is not sustainable.
Coal-fired power stations traditionally supplied baseload electricity. While some coal-fired generators have the flexibility to ramp up and down to provide flexible output, this is typically over a small range with the generating units having a minimum operating level of between 40 and 60 per cent of maximum output.
Below those levels, they must either shut down or burn expensive auxiliary fuel to remain operating. And even when ramping up and down in the ‘“normal operating range, additional wear and tear is incurred which increases maintenance requirements and costs.
Therefore, coal-fired generators do not have the inherent flexibility required to provide efficient firming capacity in the NEM, as more and more solar and wind generation enters the market.
As renewable energy captures more market share, the limited flexibility of coal-fired generators will make it increasingly difficult for that group of generators to be responsive and maintain profitability and there will likely be closures of several coal-fired generators over the next decade or so.
These closures are broadly considered to be a positive outcome in the context of longer-term energy policy and climate objectives.
However, governments and some major industrial users have concerns about the ongoing reliability of the electricity grid as traditional dispatchable capacity (coal-fired power) is closed.
The proposed certificate capacity mechanism
The ESB proposal for a so-called certificate capacity mechanism is intended to address those concerns, however, it potentially creates as many issues as it attempts to resolve.
The ESB states that the proposed capacity market’s purpose is to,
… explicitly value capacity to provide an ‘investable’ and enduring long-term signal for the competitive provision of the right mix of capacity as the generation mix transitions to higher levels of near-zero marginal cost variable renewable generation [my emphasis].
While the purpose of a capacity market appears to be to strengthen investment into the future reliability of electricity supplies, it does this assuming all capacity can be treated equally – which is not the case.
The obligation is on retailers to acquire sufficient capacity credits to meet a predefined standard (options include covering; P50 demand, P10 demand, actual demand, etc.).
Further with the introduction of additional pump storage and battery energy storage, the system may become more energy-constrained rather than dispatchable capacity constrained in time.
The need for flexible and responsive capacity
Variations in renewable energy can occur rapidly, with output rising and falling as the wind changes or as cloud cover moves across a solar farm. Geographical factors and weather patterns also come into play, as does the infrastructure built to harvest and deliver these energy sources.
To respond to this variability, the electricity market needs to develop differentiated, highly flexible, highly responsive capacity: a combination of, for example, pumped hydro, battery energy storage, and at least for the foreseeable future, fast start gas turbines or engines, that can respond quickly to variations in renewable energy production and maintain supply reliability to consumers.
As discussed above, the less flexible coal-fired generators are much less suited to providing the required response and flexibility to maintain supply reliability.
The existing generation fleet costs are sunk costs, i.e., the investment decisions have been made in the past and the costs of those investment decisions cannot be reversed. Stay-in-business capital is only a small proportion of the cost of new capacity.
Therefore, a capacity market that rewards firm capacity uniformly, will create incentives for the less flexible coal-fired generation to remain in service and deter more flexible and responsive capacity to enter the market and replace it. This is contrary to the stated ESB purpose of providing the ‘right mix’ of capacity.
Of course, the level of required capacity credits could be set so high that existing coal-fired generation would be retained, and large amounts of more flexible and responsive capacity would also be required. But this would be a massive over-investment in capacity which would be passed on as unnecessarily high costs to consumers.
An example of the sort of excess costs that can be imposed is the Western Australian capacity market which is part of the Western Australian Wholesale Energy Market (WEM) market design.
The 2014 review of that market found that consumers paid excess capacity costs of more than $110 million per annum between 2007-08 and 2015-16 or $5-$6/MWh for every MWh sold.
If this approach was implemented in the NEM, scaling the excess costs up would be many hundreds of million dollars excess capacity payments per annum.
A better alternative to support the right mix of capacity
An alternative and arguably more efficient approach to resolving any concerns about ongoing reliability of supply is to raise the market price cap to increase the incentives for highly flexible and responsive generation to enter the market, especially if the NEM desires flexible generation and storage that can respond to very high and low five-minute prices linked to quite unpredictable and increasing proportions of variable renewable energy (VRE) generation.
This is a simple change to an existing market parameter, which avoids the complexity, risks and costs associated with introducing a new, unproven market mechanism.
The NEM is currently subject to a market price cap of around $15,100/MWh. Entrant capacity might need these prices for around 6 to 8 hours per year to justify entry (approximately $90k to $120k per annum). The market price cap rises slowly each year roughly in line with inflation – in accordance with the NEM Rules.
Recent studies into the value that consumers place on reliability show that value as being between $40,000 and $100,000/MWh. The long history of economics tells us that markets that are subject to price caps tend to suffer supply shortages as supply is capped out below the level that consumers are willing to pay.
Raising the market price cap to say $45,000 – $60,000/MWh would mean that entrant generators would need these prices for a total of only two to three hours of five-minute prices on average over a year, to justify entry.
It would also impose a higher financial cost on retailers that remained exposed to spot prices; hence it would create higher incentives for retailers to contract with existing and entrant capacity.
Therefore, a higher market price cap would create the need for higher levels of contracting, more innovative forms of contracting and bring forward more flexible and responsive capacity.
It would also reward existing coal-fired generators to the extent that they were available and responsive to variations in demand, enhancing their profitability and allowing them to remain in service until replaced by more flexible and responsive entrants.
A higher market price cap would also create much larger incentives for efficient demand management, an alternative means of managing supply reliability.
Lifting the market price cap does not mean rising average prices
Opponents of raising the market price cap, often cite the increase in the context of average annual wholesale prices in the order of $50 to $100/MWh, but this reflects a misunderstanding of how the market works and how prices are passed to consumers.
Six hours of prices at $15,100 adds around $10/MWh to annual average prices. Two hours at $45,000/MWh also only adds around $10/MWh to annual average prices.
And of course, most consumers purchase electricity at fixed prices via retailers that hedge their exposure to the wholesale market through electricity generators, and so are not exposed to these prices as they occur.
Electricity supply curves tend to be highly elastic to the extent that supply is contracted and highly inelastic to the extent not contracted.
In the higher market price cap scenario, additional contracted capacity will likely suppress prices for many periods that would rise to $15,100/MWh with the current market price cap in place (typically prices would be held at or below $300/MWh – the strike price of a standard cap contract).
Only a few of the periods would rise to the much higher price cap. The effect on overall prices would be small and the mix of generation would be closer to the “right mix of capacity” envisaged by the ESB.
This is confirmed by ACIL Allen internal modelling which indicates that increasing the market price cap to between $45,000 and $60,000/MWh will bring forward sufficient additional investment in highly flexible and responsive generation, suited to a future in which more renewable energy investment occurs, while not delaying the closure of coal-fired generators and having minimal effect on overall annual average electricity prices.
Contrary to the view that raising the market price cap to these levels being undesirable, we consider doing so is in the best interest of consumers.
Conclusion and way forward
Even the best-designed capacity mechanism is likely to impose higher costs than incurred in raising the market price cap sufficiently and will also likely delay the development of the “right mix of capacity” for the future NEM.
This is likely to result in consumers paying more, for a less reliable electricity supply than if an approach involving relaxation of the market price cap was employed.
While the ESB conducted an international survey of other markets, they have provided no compelling arguments for a certificate capacity mechanism, and capacity markets have a history of performing poorly around the world.
Undertaking such a radical departure from the NEM’s current market design, which has performed successfully for more than twenty years, without undertaking sufficient research and analysis, is fraught with risk for both investors and consumers, and is likely to deliver a less reliable supply of electricity to consumers.
Paul Hyslop is CEO of ACIL Allen.