Labor pushes ahead with a controversial capacity market

What is the goal of a capacity electricity market?

You may be forgiven for not sitting through the full press conference last Thursday, where the Albanese government stated Australia would be strengthening their 2030 targets to 43% under the Paris Agreement. However, if you had, around 30 minutes in you would have heard Chris Bowen, the newly appointed Minister for Climate Change and Energy state, “in relation to the short term, State and Territory Ministers agreed with me last week, that we should proceed at haste, at pace, with the capacity mechanism. I asked, on behalf of all Energy Ministers, the Energy Security Board to proceed with that work, at speed, and they are doing that. I am very confident I will be able to get agreement of State and Territory Ministers for a comprehensive capacity mechanism and I’ll have more to say when that work is ready.”

Well that work dropped this morning (20th June) at 7am. They have given those who wish to respond until (25th July) to submit their views on this paper so at pace it shall be. However; given the response following the ESB Post 2025 paper I am not sure that any amount of noise and lobbying from the industry is going to stop this juggernaut from achieving its goal, especially since it is being backed by those generators who have the most to gain from this market. Not only that, but unless there is a big bump in the road, a first look Capacity Mechanism will be in place by 1st July 2025.

What is the goal of this market? – Well in my opinion there is only one reason that this would be encouraged and that is to subsidise coal-fired power stations which have had their financial viability severely questioned by the growing penetration of lower cost renewables within the system. Don’t get me wrong, the longer-term markets have the potential to encourage other faster starting generators onto the market, but this hasn’t really been the case in other capacity markets i.e. Great Britain (GB).

This argument is only further strengthened when looking at how the GB Market ended up achieving their stability, in their high renewable penetrated market, which is from nuclear power which has been guaranteed a strike price of £92.50/MWH or ~$163/MWh. Thus, making any capacity market payment minuscule in comparison to the underpinning of the generation at that rate.

The ESB are arguing, and convincing themselves and the government in the process, that this mechanism is the answer to AEMO’s ISP step change scenario, in which demand increases and coal exits the system. If that is indeed their argument, then they are ultimately stating they cannot efficiently run a system in which coal is not part of the generation mix and unless this is financially managed there will be a ‘disorderly transition.’

The question therefore isn’t will there be a capacity mechanism from July 25, but how centralised or decentralised will the final design be? Will it sit as a Physical Retailer Reliability Obligation – PRRO design, one in which the market determines for itself the level of the required capacity, or do we go wholly down the regulated route with AEMO determining in long term auctions (similar to the GB model which has several T-year auctions) and they forecast demand and supply to determine the required level of capacity and sell these capacity certificates to retailers to meet their requirements.

There is no grey area for the ESB, they have stated openly in the paper they wish for the forecasting and determination of the capacity requirements to be centralised and for AEMO to manage these purchases on behalf of market participants. In essence they would moderate the capacity of these generators, for a cost, at certain times of day or periods of high system stress to allow them to ensure capacity is available to the market operator when needed. End users would then pay for that management of the system and their portion of that capacity.

The other point to note, keenly hidden within the paper is the four yearly review of the Reliability Standard and Settings Review (RSSR) that is about to be undertaken, with significant interest been taken in the Market Cap, especially given the gas price cap is equating to a marginal cost of generation higher than the electricity price cap (Presuming a normal heat rate of 8-12). If the caps are risen for both the caps $300/MWh and spot $15,100/MWh markets as expected, could the requirement of ‘capacity’ in the market become a moot point? Surely the exacerbation of the current situation could be avoided if the gas generators were certain of meeting the cost of generation and you cannot truly believe that a market cannot efficiently run with enough capacity if they are achieving $15,100/MWh or possibly more?

The real key argument which has not been addressed by the paper however, is the idea that aging coal plants are unlikely to be able to ramp in time to fill the gaps between this growing renewable penetration. Therefore, the question really needs to be asked is this the right investment if you really want to transition this grid or should this be put into different technology rather than prolonging the life of unsuitable assets?

Ultimately however the bottom line remains ‘user pays.’ As such any one of the options being floated will be passed through to end users through retailer or network tariffs.

I will let the retailers and generators pick apart the nuances of the paper, but needless to say the government will be pushing ahead with this in some form, the only question will be how much say we will have in the centralisation of the market or not, and therefore how much control retailers will have on the costs of this capacity.

Written by Kate Turner, Senior Manager – Markets, Analytics, and Sustainability

AEMO Suspends the Market

Below is the media release from AEMO after it suspended the National Electricity market at 14:05 today.

AEMO today announced that it has suspended the spot market in all regions of the National Electricity Market (NEM) from 14:05 AEST, under the National Electricity Rules (NER).

AEMO has taken this step because it has become impossible to continue operating the spot market while ensuring a secure and reliable supply of electricity for consumers in accordance with the NER.

The market operator will apply a pre-determined suspension pricing schedule for each NEM region. A compensation regime applies for eligible generators who bid into the market during suspension price periods.

In making the announcement AEMO CEO, Daniel Westerman, said the market operator was forced to direct five gigawatts of generation through direct interventions yesterday, and it was no longer possible to reliably operate the spot market or the power system this way.

“In the current situation suspending the market is the best way to ensure a reliable supply of electricity for Australian homes and businesses,” he said.

“The situation in recent days has posed challenges to the entire energy industry, and suspending the market would simplify operations during the significant outages across the energy supply chain.”

Edge wish to reiterate, this is not a physical supply issue. AEMO directed 5GWhs of physical generation into the market. If generators can operate when under direction, they do not have a physical reason to not generate (such as maintenance, overhaul etc), so the reduced availability we are seeing has to be a commercial trading decision to either price volume into higher price bands or to remove availability in the maximum availability bands of their bids. The availability is there, the generators are just not offering it via the spot market.

The market suspension is temporary, and will be reviewed daily for each NEM region. When conditions change, and AEMO is able to resume operating the market under normal rules, it will do so as soon as practical.

Mr Westerman said price caps coupled with significant unplanned outages and supply chain challenges for coal and gas, were leading to generators removing capacity from the market.

He said this was understandable, but with the high number of units that were out of service and the early onset of winter, the reliance on directions has made it impossible to continue normal operation.

The current energy challenge in eastern Australia is the result of several factors – across the interconnected gas and electricity markets. In recent weeks in the electricity market, we have seen:

  • A large number of generation units out of action for planned maintenance – a typical situation in the shoulder seasons.
  • Planned transmission outages.
  • Periods of low wind and solar output.
  • Around 3000 MW of coal fired generation out of action through unplanned events.
  • An early onset of winter – increasing demand for both electricity and gas.

“We are confident today’s actions will deliver the best outcomes for Australian consumers, and as we return to normal conditions, the market based system will once again deliver value to homes and businesses,” he said.

What does it mean for generators and end users.

  • Bidding and dispatch will continue as usual under the market rules.
  • Dispatch instructions will be issued electronically via the automatic generation control system as usual
  • If required AEMO may issue dispatch instructions in any other form that is practical in the circumstances.
  • Spot prices and FCAS prices in a suspended region continue to be set in accordance with NEM rules or under the Market Suspension Pricing Schedule.

The Market Suspension Pricing Schedule is published weekly by AEMO and contains prices 14 days ahead.

The market will continue to operate under the Market Suspension Pricing Schedule until the Market operator determines the market is able to return to normal conditions and the suspension is revoked.

Article by Alex Driscoll, Senior Manager – Markets, Trading, and Advisory

Drivers behind potential load shedding

In the energy market, probably not unlike most complex markets / industries, we never let the truth stand in the way of a good mainstream news story. So much so, at Edge we struggle to watch mainstream news!

Yesterday Edge highlighted that a tight supply balance was not the key driver for the unprecedented high prices occurring in the spot and contract markets.

As previously outlined, generators bidding behaviour is playing a pivotal role, lifting the average price in the spot market as their spot traders shift volume into higher price bands. This pushed spot prices so high that on Sunday the market reached the cumulative price threshold (CPT). This means that the sum of spot prices in a seven-day period hit a level which caused AEMO to intervene and cap prices until the market returns below this threshold.

As has been widely discussed on Sunday evening, AEMO stepped in and controlled the spot price once the sum of the previous 2,016 (7 days) trading intervals equalled the cumulative total of $1,359,000. The cumulative CPT is equivalent to an average price of $674.16/MWh for the seven-day period.

During market intervention, spot prices in the relevant region are capped at $300/MWh.  This commenced at 6.55pm on Sunday night in Queensland and will continue until the 7-day average drops below the CPT. Once this is achieved the CPT remains on foot until at least 04:00 the next trading day.

Since Queensland hit the cap on Sunday, we have now seen every mainland region in the National Electricity Market (NEM) also hit the CPT. As at publication, intervention pricing is currently enacted in all of these regions (QLD, NSW, VIC, and SA). Tasmania is currently under threat also.

During market intervention the maximum spot price can only reach $300/MWh (there is also a floor of -$300/MWh). $300/MWh is currently lower than the short run marginal cost (SRMC) of many gas generators when priced against the current gas price, which is also currently capped by AEMO (at $40/GJ).

A consequence of capping these markets is higher priced generation withdraws from the electricity market, as an example gas generator have a Short Run Marginal Cost (SRMC) of generation of roughly $400/MWh based on a fuel cost of $40/GJ, but with a cap of $300/MWh on the electricity generated it results in generators removing their availability from the market which in turn results in regional availability dropping. Hence subsequent threats of power outages and the potential requirement for load shedding.  It’s a case of the market being more under threat from commercial drivers than physical drivers.

The commercial dynamics of the current market create a perceived lack of availability in the market and leads to generators looking to other (non-capped) revenue streams for their generation stack. This is precisely what occurred over Monday with 607MW of availability being removed from QLD available generation, and 930MW removed from NSW. The drop in dispatchable generation resulted in AEMO publishing a Lack of Reserve (LOR) forecast and requests by AEMO for a market response. Rather than this call being answered, generators held firm and did not place generation back into the traditional bid stacks.  Across Monday the LOR dropped further as more generation disappeared into the ancillary market and as we approached the evening peak AEMO called an LOR3, which resulted in AEMO also calling on Reliability and Emergency Reserve Trader (RERT) providers to fill the availability gap.

Overnight AEMO’s action on calling RERT prevented load shedding, however this may not be the case in NSW tonight where 590MW of load is forecast to be interrupted at 19:00. If there is insufficient support under RERT to compensate for this supply shortage, we could see load shedding.

With all mainland NEM regions currently operating under the CPT we expect to see more market intervention, and those generators exposed to a capped gas price removing volume out of the market as electricity prices are capped at levels below their SRMC. This is likely to see AEMO needing to intervene in other regions, invoking RERT to source additional availability, or failing that load shedding.

Article by Alex Driscoll and Stacey Vacher.

High electricity prices – What’s really driving them?

Written by Alex Driscoll, Senior Manager – Markets, Trading, and Advisory

In recent weeks we have seen a rapid increase in the cost of electricity both in Queensland (“QLD”) and New South Wales (“NSW”).

The chart shows how spot prices (light blue line) and forward prices in QLD have increased considerably since mid-2021. Most notably, we’ve seen frightening increases since mid May 2022.

The question is, what is really driving these unprecedented high prices?

Underlying fuel costs are playing their role, as we’ve seen significant increases in the cost of gas and coal resulting from the Ukraine crisis. Recent weather conditions on the east coast of Australia have also adversely impacted coal deliveries.

Analysis of the supply / demand balance and the bidding behaviour of participants is also in focus. Whilst underlying fuel prices have had a part to play, trading behaviour appears to be playing a leading role in the most recent electricity price increases. At a high level, the structure of the bid stack is a key driver to volatility occurring in QLD and NSW over the past few weeks.

Having analysed the market Edge2020 have found that small changes in the supply / demand balance coupled with strategic bidding behaviour has had a significant impact on spot prices.  Edge2020’s analysis shows that as solar generation diminishes the market power and influence on the spot price shifts from intermittent generation such as solar, to thermal generators such as gas-fired and coal fired generation.  With surplus availability of generation across the states, high demand or scarcity of supply are not the key drivers for the higher prices.

Both QLD and NSW bid stacks reflect the recent strategic bidding of generators in these regions. The bid stacks show how peaking plant are dispatching units at elevated prices, well above levels supported by inflated gas prices. Bid stacks also indicate that coal fired generation is not operating at full capacity. In the absence of news to the contrary, we can assume that output has been restricted for commercial reasons rather than technical limitations. Noting that no re-bids with technical limitations were published during the period analysed.

As spot market volatility has increased, as to have prices across the forward market, with uncertainty and risk having been priced in significantly. Views on future fundamentals remain broad, resulting in differing strategies between forward traders. Whilst spot traders successfully maintain unprecedented volatility in spot prices however, it’s difficult for forward traders to sell into this market. Once the opportunity presents to do so, we could see significant spreads and chunky declines in forward pricing.