AEMO adds to the spooking of the Energy Market post Liddell Shutdown

Energy Market - AEMO _ Liddell Shutdown

On Thursday (25th May 2023) AEMO released their Scheduling Error notification (incident number 54) confirming they had incorrectly scheduled three of the Liddell units into one of their systems, post the Liddell shutdown, which caused price spikes across the NEM and forwards market on the morning of 1st May 2023.

As has been widely documented the last three Liddell units came offline on the 24th of April (Unit 4), 26th April (unit 2) and finally unit 1 on the 28th of April. This should have flowed through to the systems within the AEMO dispatch engines, however due to an error this was not the case, and the market was affected by the error between midnight and midday on the 1st of May 2023.

The error was cause by a mismatch of data used within the systems which feed the NEMDE (NEM Dispatch Engine) used by AEMO, whereby one part of the system removed the units from 00:01 on the 1st May. However, a separate part of the NEMDE’s data feed system, which controls the constraints still included the Liddell units at their “initial values” i.e. 500MW, not their real value of zero.

When the equations within the constraint tried to equalise, there was a “drop” of 1500MW on one side of the equation from the first interval on the 1st May 2023.

To rectify this AEMO reduced flow coming from Victoria into NSW and around 173MW of generation was dispatched down.

Prices reacted as expected with 6 periods between midnight and 6am having prices between $2,771.58/MWh and $2,964.04/MWh and increasing the daily average price by around 30% to an average of $288.86.

With a marketplace reacting to every cough of a power station, especially in the days following the Liddell closure the added constraint was enough to also strengthen the forwards market with the Q323 close price rising $5.50/MWh on the day in comparison to the day before across QLD, Vic and NSW and even SA was affected with an $8/MWh increase on the previous days close.

This strength continued into the next few weeks as outages came into the mix, a tube leak delaying the return to service of Bayswater 2 to the 3rd May, Kogan Creek, Eraring 2 and Tarong taking outages, the return of Callide being delayed and an unexpected interest rate hikes putting additional pressure on the market. Speculators were quick to act trading the spread between states thus increasing prices across the NEM.

This reactionary sentiment is one we feel will remain for a while, with the spot market quickly correcting however the futures continue to hold value down the curve.

Possible extension to the gas caps

Image of Gas Stove

It is likely today that the Climate change and Energy Minister Chris Bowen will announce an extension to the $12/GJ cap on wholesale gas. Currently the gas caps will expire at the end of the year. Following the release of the draft mandatory code of conduct the market will have several weeks of consultation.

Energy producers are likely to be concerned over an extension or possibly permanent changes to the wholesale gas. Energy producers will also be concerned that changes will impact the pricing of long-term deals as it is likely a reasonable pricing clause will be included.

Under the reasonable price provision, gas companies could only charge a price based on the cost of production plus a reasonable margin. The reasonable price does not consider the capital invested during exploration and development of projects. Gas buyers will be able to challenge the price of contracts via a formal dispute process. The dispute process is designed to determine what the ‘reasonable’ price should be.

While the extension to the cap mechanism will provide certainty for energy users, energy producers remain in a holding pattern.

Gas producers are not finalising new gas supply contracts for 2024 until the government confirms what the impact of the code will have on pricing.

The federal government have also set the expectation that the federal budget will include a Petroleum Rent Tax. The Australian Petroleum Production & Exploration Association (APPEA) have shared with its members concerns that changes to the taxing of gas producers will add $100B of tax receipts to the government.

To appease the gas production sector, it is expected the new code will allow for exemptions. New projects that add supply for domestic use may qualify for exemptions from any specific pricing provision.

APPEA said the code “must recognise the importance of gas in a cleaner energy future, and the need to ensure settings which enable investment in new supply to avoid forecast shortfalls and put downward pressure on prices”.

Gas industry developers continues to warn the broader industry that deterring investment in new gas supply will harm the supply to manufacturers and reduce the secure of supplies of electricity across the NEM.

Beach Energy’s chief executive has said that getting the terms of the code wrong could imperil Australia’s transition to low-carbon energy given the role gas plays to support renewable energy.

At the end of the day changes to the industry need to benefit producers, end users and ensure gas and electricity security is achieved. While international cost pressures are impacting the gas and electricity industry. The continued development of gas resources are required to provide gas the opportunity to be the transitional fuel as Australia strives to its Net zero emission targets.

Next test in NSW for the transition to renewables

Hand turning off light switch

For over eight years, there has been talk of AGL shutting down Liddell power station. Finally, this will become reality today, with the next Liddell unit being shut down.

Liddell Unit 4 will be shut down today, followed by Units 1 and 4 over the next 10 days. The retirement of Liddell power station will make 10% of NSW’s availability being bid unavailable.

It would be expected that the permanent closure of 10% of NSW’s electricity generation would put the grid at risk and lead to higher electricity prices.

AEMO has alleviated market concerns by saying, “Supply is not at risk”. However, Edge2020 is not ruling out an upward pressure on prices due to a shock to the market, despite the market knowing the Liddell units would be shut down for many years.

The retirement of Liddell power station is the next big step for NSW as the state transitions from scheduled coal-fired generation to intermittent renewable energy and storage.

While the market has known about the retirement of the Liddell power station for years, Edge2020 expects the market to be firm on the reality of the closures. Spot electricity and forward prices in NSW and Queensland may increase in the short term; however, they will settle over time.

Following the retirement of the Liddell units, availability will still be relatively high in NSW. The capacity factors of the remaining coal-fired units will increase, and gas will fill the remaining gaps. As a result of this and generation from neighbouring regions, it is unlikely that the NSW region will incur a significant drop in availability resulting in a Lack of Reserve (LOR) notice from AEMO.

AEMO confirmed in February that the closure of the Liddell units would not breach the reliability standard; however, AEMO’s latest reliability report has raised concerns that reliability risks remain in NSW. AEMO’s biggest reliability concern has been the delayed delivery of Snowy Hydro’s Kurri Kurri gas-fired generator. The Kurri Kurri gas-fired generator has been delayed by 12 months. AGL has confirmed AEMO has not approached them regarding reliability levels following the closure.

Further to alleviate the availability and reliability concerns of the market as we approach to summer is the news that Energy Australia will have the 300MW Tallawarra B gas-fired generator online in December. Additionally, NSW imports additional electricity from Queensland and Victoria via the interconnectors.

AGL has plans to repurpose the Liddell site into a clean energy hub which will include a 250MW battery with room for expansion that could be linked to a nearby pumped hydro project.

After the closure of Liddell 4 on April 19th, followed by Unit 2 six days later, and then finally Unit 1 on April 29th, AGL will start demolition in early 2024.

The next few weeks will be an interesting time in the industry, particularly for NSW politics and the wider NEM. Edge2020 will monitor the market and provide updates over the next few weeks as the final unit retires.

Renewable energy storage road map released

Edge 2020 Brisbane City

The CSIRO released its Renewable Energy Storage Roadmap at the end of March 2023.

Their modelling suggested that while Australia leads the world in solar generation, and we have reduced emissions significantly, there is still a big task ahead of the country if we are to meet net zero emission targets and maintain affordable and reliable energy to end users. The CSIRO Renewable Energy Storage Roadmap report showed Australia will need significant amounts of storage to meet the transition to renewables.

Storage is the key to integrating renewable energy into the grid and reducing the dependency on coal and gas fired generation. Currently the electricity produced from renewable sources such as wind and solar is intermittent and is not easily dispatched into the grid when it is most needed. Storage allows the renewable energy to be generated when the natural resources are high and dispatching it into the grid when the electricity is needed.

Dispatchable storage is currently available in the grid in the form of pump storage hydro, such as Wivenhoe power station in Queensland and Tumut 3 in NSW. There are also various battery installations located across the NEM.

The dispatch of renewable energy may require different storage technologies to best suit an evolving NEM. Storage comes in various forms from electrochemical storage such as batteries, mechanical storage such as hydro, chemical storage and thermal storage. Each technology has its pros and cons, but a combination of technologies is likely to be required to meet the real time storage volumes and timings of the NEM.

For many years pumped hydro has been seen by governments as the solution to Australia’s energy storage needs, but timing is the limiting factor in this solution.

To enable the transition from coal and gas fired generation to renewables, storage is required now. On a typical day we have excess solar generation resulting in negative spot prices, however over the evening peak as demand increases the supply of renewable drops of coal and gas provide the generation to meet demand. Thermal generation is normally dispatched at prices higher than the cost of renewables resulting in higher spot prices. If storage could be used efficiently the solar energy produced during daylight hours could be used over the evening peak and into the evening resulting in lower electricity prices.

As coal fired generation retires between 2023 and 2035, new dispatchable generation needs to be brought online, the CSIRO report states, development timelines need to be accelerated to bring more projects online by 2030.

Pump storage hydro typically has a lead time of 10 years so either development timelines need to be accelerated or different storage technologies need to be employed in the meantime.

CSIRO chief executive said “there was a need for a “massive increase” in storage capacity to achieve the transition to net zero, with estimates of 11 to 14 gigawatts of additional storage capacity by 2030 alone.

2030 is not far away, to meet the transition targets should industry be focusing on storage rather than generation? Is storage an opportunity to utilise existing infrastructure like old mine pits for pump storage hydro or repurpose retiring thermal power station sites as storage hubs?

Solar and wind are the big losers in latest AEMO MLF forecasts

woman on a windy day

As the electricity market evolves the Australian Energy Market Operator (AEMO) makes assessments of the changing landscape from a transmission and security of supply perspective.

Recently AEMO released its final assessment of Marginal Loss Factors (MLFs). MLF determine how much energy is lost between the generator and the region reference node in each state.

In this next round of MLFs many of the big losers are the intermittent generators. Changes to the grid and the closure of thermal generators have had a detrimental impact on wind and solar farms. Lower MLF’s impact the amount of revenue generators can make.

The final MLF numbers are not as bad as what was published in AEMO draft report providing some positive news for wind and solar developers. Since the draft report new modelling has included the delayed return to service of the Callide C units.

The primary driver for changes in the new MLF forecasts has been changes in availability due to the closure of Liddell, revised return to service dates for Callide C, revised demand forecasts and the increased penetration of solar and wind generation into the grid.

Recent transmission line work has resulted in an increased capacity between Queensland and NSW which means increased flows from Queensland which results in wind and solar projects located in the north of NSW being constrained.

MLF generally gets worse for generators at the end of a long transmission lines, this has resulted in generation in northern NSW being the big loser this year. Some solar farms in the New England region have dropped by over 3%.

While a 3% fall sounds bad, it is not as bad as the MLF for Moree, a 57MW solar farm in western NSW which loses over 20% of its generation by the time it gets to the regional reference node. Previously Moree solar farm had an MLF of 0.8275, this year it is 0.7977.

The return to service of Callide C significantly impacted solar farms in central Queensland, however the delayed return to service has lessened the impact. Daydream, Collinsville, Kidston, and Moura are some of the solar farms most impacted by the new MLFs.

So what does the mean to end users? While we are seeing a rapid increase in renewable generation, the location of this generation is important to the success of a project. If we use the example of Moree where over 20% of the renewable generation does not reach the market then the question has to be, was it built in the correct part of the grid. Many people focus on the size of the project while the volume of electricity produced needs to be of greater importance. Unfavourable MLF will impact the success of the project, will reduce the renewable energy available to the market and potential can leave end users with less renewable energy than what they had signed up for.

International oil price fluctuations and the electricity market reacts

Organization of the Petroleum Exporting Countries (OPEC+), the intergovernmental organisation of 23 oil exporting nations mainly in the Middle East and Africa (with the original core 13 holding most power) is the body which is responsible for around 40% of the world’s oil production. In early October this group agreed to slash the output of crude oil by 2 million barrels a day. To put this in perspective Saudi Arabia produces on average 10 million barrels per day of the current, already reduced, 42 million barrels coming from the OPEC+ nations and this 2-million-barrel reduction translates to about 2% of the global oil supply. It is also worth noting in 2016 when OPEC became OPEC+ Russia joined the organisation and has held a strong voice ever since.

This reduction in production, shows a sign of deepening rifts between the Middle East and the US, and the cynic in me says may be more than slightly linked to the upcoming US mid-term elections where the democrats are already looking weaker than their GOP counterparts – not that those countries have ever influenced an American election in the past *Cough Trump Cough*.  But regardless of motives these new production limits will come into place in November and the impending reduction in production has repercussions which flowed through the broader Australian and global energy markets including oil, coal and gas.

Australian electricity prices are strongly correlated with the international crude oil price, particularly in QLD and NSW, the impact of Brent crude futures hitting a high of $US93.39 on Monday caused a rally on the Australian electricity market, with the Q123 QLD price rising 20%, as the effect of this increase translated to the domestic electricity market. Brent Crude being the international oil benchmark price.

However, OPEC+ are not the only drivers of the oil price, especially WTI and Brent prices. The US dollar, on the back of a fear of a global recession has been strengthening which has dampened the demand for their oil on the international stage. (Consider the FX implications of a strong dollar, if you are buying from Europe the same amount of crude oil now costs more as the number of Euros to achieve the same dollar amount has increased). So, a reduction in demand of America Oil due to FX and reduction in export from OPEC+ can only move the needle up in price regardless of source.

We also cannot ignore the ongoing COVID implications in Asia, especially China. Their glut of demand has not returned to anywhere near the pre-pandemic levels and as such that demand is not translating into a price war to ensure delivery of the commodity. Conversely to above this is actually holding prices lower and reducing the impact of the OPEC+ reduction.

But there is no ignoring the elephant in the room, the impact of Russia’s invasion of the Ukraine, which has led to global increases in commodity costs, has also acted as a buffer to the oil price despite the recession fears. As many countries imposed their own moral code and refused to buy Russian oil, other sources could benefit from the increase in demand. By the end of September this year Russian oil was trading at $20/barrel cheaper than its Brent counterpart. Some less scrupulous countries such as India and China, sought to benefit from this price differential and ignored the sanctions coming from the West and are now taking at least half of Russia’s oil exports. Further, Russia has now overtaken Saudi Arabia to be the biggest exporter of oil into China. Therefore, could the cut in reduction be as simple as the rest of OPEC+ looking to balance the loss in demand from the East by passing inflated prices to the West?

But back to Australia, we are obviously a commodity rich nation, however with our internal thirst for electricity and therefore generation linked heavily to the export price of that commodity, we are subject to these international fluctuations also. As the price of the oil increases, the global demand from that commodity shifts to other sources. Our gas and coal price domestically are therefore linked heavily to the price that exporters can achieve if they send our home-grown coal and gas abroad. So as the demand shifts from oil, to gas or coal so does the price. Hence the correlation described above with Brent rising and that coming into our domestic market.

Then for fun lets add in our own pressures, we are expecting another La Nina this year, last year’s summer La Nina brought low solar output coupled with flooding, wet coal stockpiles and just-in-time delivery delays due to the tracks being flooded and trains not able to deliver.

We also have an economy which is having increasing inflationary pressures. These inflation increases will flow onto the interest rates (including the interbank rates) and therefore commodity prices. How? Well, a retail return is based on 2 main drivers, network and wholesale costs, the latter we have covered above. But in isolation network costs will also increase, due to the inflation increasing the nominal value of the asset and therefore the increasing value of the debt as the interest rates increase also.

Further any investment required to transition our market to greener fuels will also be increased, as the levelized cost of electricity for these new assets is also increased due to cost of capital and higher interest rates feeding through. As such the ‘Energy transition’ will now cost more.

There is also a regulatory driver, with an impending price cap increase being fast tracked, this will allow system stability to flow through, as gas won’t withdraw at the $300/MWh cap as this looks likely to be increased to $500/MWh. Therefore, does that become the new ceiling of our market?

There is an old idiom that when China sneezes Asia catches a cold, I unfortunately think this now needs to be broadened to when any imbalance occurs the ripples will be felt globally.

The balance is so tight that without some easing of any fundamentals the shocks will continue. AEMO are acknowledging this, but despite acknowledging the issues they are desperately clinging to the hope a capacity market will be the silver bullet to system stability, backed by large synchronous generators, not that they have any benefit from that mechanism. However, I cannot agree, point in fact I point you to the black outs in the UK on August 9th 2019, a market which has had a capacity mechanism for many years yet in a moment of system instability these ‘capacity assets’ could do nothing and they experienced a blackout for 45 minutes and over 1 million people were affected.

What this means for us is without regulation around bidding behaviour based on cost of generation from hedges not advantageous forward prices, we are looking at another summer with uncertainty and volatility based on international fundamentals pulling the Australian market along for the ride.

Winter is coming

Now I am a major Game of Thrones fan, but I never thought moving to Australia that I would turn into Ned Stark and constantly worry about a Northern Hemisphere Winter. But, as we are hurtling towards those cooler months in t’north and following the tumultuous Q2 and start of Q3 in the NEM, I am preaching that the Northern ‘Winter is Coming’ and even down here in Australia we must be ready.

As background Northern Europe, UK, France, Belgium, Germany etc., rely on feeds of Gas from Norway and Russia. Gas is significant in Europe as a 1-degree shift in temperature can result in around 5% of domestic demand increase, or decrease, due to most homes being heated via Gas-Central heating. With a third La Niña about to be called in the Southern hemisphere and La Niña, correlated with colder winters in Europe, with increased snowfall, as it shifts the jet stream north to the pole and increases storms across Northern Europe, this can only mean an increase this heating demand.

This confluence of events would usually increase my concern for a tight supply in the European market, but this year is different. Ignoring for now the Russian flows, we will circle back to that later, Norway’s Energy Minister has already raised the possibility that they may restrict electricity exports with possible restrictions to Gas flows as well. With much of their electricity coming from hydro, and after an un-seasonably warm summer period, Norway has stated the priority will be to refill the reservoirs over winter, rather than secure the energy supply of their European neighbours. With this flow being restricted into Northern Europe, coupled with a diminishing fleet of coal and nuclear options, gas will be the favoured source of domestic supply for Northern Europe. Although there are other interconnectors, it is anticipated these will either be significantly under utilised or such a price differential within a domestic market will occur to ensure flows to a single market will ensue. This could be facilitated by pushing those areas (countries) price up to exorbitant amounts to ensure flow across the interconnector and shore up domestic supply. With flows of course favouring higher priced regions.

Now let’s put Russia into the mix. Russia announced this week that the Nord-Stream 1 pipeline, a crucial pipeline for gas flow into Europe, required maintenance from the 31st August. This happens to coincide with European markets trying to firm up winter supply by filling storage and Russia increasing aggression to the Ukraine, but I am sure that was a coincidence.

The 3-day maintenance will have a return to service for the 2nd September. But how likely is this to return? Well, if the last outage is anything to go by, where only 40% of the required flow reached Europe and the delivery of the required turbine was strangely delayed, the price increase was significant and totally in Russian control. Now with this latest outage and flows expected to be around 5% of the obligations agreed with the EU, the cynic in me wondered if Putin is trying to offset the sanctions place on Russia by pushing the cost of Gas to exorbitant amounts. If he can sell his 5% for the same as the revenue from the already inflated 40% and free the remaining gas for sale to more amiable neighbours, he is in a win-win situation.

The real fear is that this flow remains low for the whole of Europe’s winter, which would not only put massive strain on the cost of generation but also lead to many retailers simply not able to meet their obligations and go under. There is also a risk of lack of supply and therefore blackouts as well as increasing costs on an already strained economic environment.

To mitigate this, European generators are throwing out their climate targets with the baby and the bath water in favour of supply and are scrambling to shore up gas supply and return coal-fired power stations from cold storage. The Mehrun Coal-Fired Power plant in Saxony Germany came back online at the start of August, Uniper have just announced they are re-commissioning the Heyden plant in North Rhine-Westphalia and in the UK, the government has made moves to re-open the rough gas storage facility, 25% of it initially, ignoring the safety concerns which led to its original closure. But this will not be enough, and this is where Australia needs to brace itself for a secondary wave of impacts.

LNG and coal exports into Europe will increase, as the price differential will be significant. The ensuing impact through the JKM on the domestic gas market, and coal export price will affect the replenishment of the longer-term running costs of our own generators.

Although significant volume should be pre-hedged, these prices will start feeding through, nothing is stopping the trading opportunity cost being passed through by generators. They will argue the replenishment of the stockpile will need to factor these spot and forwards prices, interesting that doesn’t flow through in a bear’s market though.  What does that mean for our summer, well it means the high prices aren’t going anywhere fast. The shortage of supply in the NEM may be diminished, with most, if not all units now returned from overhaul, yet the price is continuing to take advantage of, and reflect the international fundamentals rather than the real long run average cost of the asset.

With the Capacity Mechanism being put on ice and strengthening Safeguard Mechanisms already announced by the Labor Government, coupled with favourable international fundamental conditions providing political cover for generators, could this be the last hurrah for coal and gas generators to eek the last value from these assets?

Either way be under no illusions, with the Northern winter hurtling towards us, European prices already building in shortfalls in supply and no end to the Ukraine conflict in sight, the Vega sensitivity is going off the chart and is not going to be subsiding anytime soon. As such Australia, and especially its energy markets need to brace, for the fallout.

To circle back to Game of Thrones, Ramsay Bolton stated, “If you think this has a happy ending, you haven’t been paying attention” for ‘winter is coming’ and we must be prepared.

Market Update – Q3 2022 to date

As we move out of Q2 2022, a quarter that we have never seen behave in this way before, it is interesting to see how things have changed in Q3 to date.

Why was Q2 2022 so controversial? Well, we saw record spot prices, record forward prices, caps put on the gas market, caps put in place in the electricity market, market direction, the activation of Reliability and Emergency Reserve Trader (RERT) and eventually suspension of the National Electricity Market (NEM). As we moved through Q3 has the situation changed?

To make this decision we must first review Q2, to assist us in understanding if things are going to change. What caused all the market intervention in Q2 and the eventual market suspension?

Q2 is normally a quiet time in the NEM, demand is low, and generators take the opportunity to take units offline for routine planned overhauls. The drop in availability that results from the units on overhaul are normally soaked up by the remaining units online. This Q2 we saw a lower than normal number of units online across the NEM to take up this slack, namely Callide C4 that was offline due to the catastrophic failure in May 2021, Swanbank E and thermal generators dispatching less volume due to flooding across NSW and QLD reducing coal supplies.

Q2 2022 saw average spot prices more than double compared with recent years and peaked at the end of the quarter. The average for Q2 2022 reached $332/MWh in Qld, $302/MWh in NSW, SA at $257/MWh and VIC the lowest, at $224/MWh.

Interestingly the quarterly average price for NSW and QLD was above where the Administered Price Cap (APC). The APC is triggered when the sum of the previous 7 days trading intervals equals $1,359,100. The price is then capped at $300/MWh and remains in place at least until the end of the trading day.

Q2 2022 was a quarter of extreme price, low availability, and market interventions. In Queensland for example we saw 42 hours of spot prices below $0/MWh but also 32 hours above $1,000/MWh. While we did not see a significant number of prices reaching the market cap of $15,100/MWh we did see solid prices that increased the average to levels not normally seen in Q2.

During Q2, exacerbating the issue, we saw significant volume bid in below $0/MWh so units would remain online, however with little between this price and higher prices meant there was a visible gap in the bid stack until prices were over $300/MWh. This distribution was a result of higher fuel cost such as spot gas at $40/GJ which converts to a generation price of over $400/MWh. However, we also saw the emergence of strategic bidding that introduced volatility and higher average prices into the market. The result of the strategic bidding was spot prices for the majority of the time across the NEM were above $100/MWh and often above $300/MWh.

As coal supplies became limited due to flooding, the gas price also jumped due to the global supply issues caused by the war in Ukraine. These fundamentals led to the spot prices increasing and eventually forcing the market operator to cap the market when the Administered Price Cap was reached. APC put a cap of $300/MWh on the electricity spot market.

As a result of the APC, generators removed capacity out of the market rather than operating at a loss due to their higher spot fuel cost. This resulted in the removal of over 3,000MW of generation in which forced AEMO to intervene in the market and direct units online as well as being forced to activate RERT to maintain system security.

Over a few days operating under the APC the market became impractical to operate using directions and AEMO eventually suspended the market on 15 June 2022.

During market suspension AEMO took over the control of the dispatch of market participants units.

Simultaneously during the market suspension, availability returned to the market as units returned from overhauls, coal and gas supply restriction improved and trading strategies were reviewed by the market participants.

On 24 June 2022 AEMO lifted the suspension of the market and the NEM returned to normal operation.

Since the lifting of the market suspension and the commencement of Q3 we have seen a change in some behavior, however spot prices remain high. In the first week of Q3 market participants took advantage of market conditions of low intermittent generation ensuring they benefitted from the ability to increase volatility. In the first week spot price hit the new maximum price cap of $15,500/MWh on several occasions.

While these price spike has lifted the quarterly average for the first 21 days of Q3 to $466/MWh in QLD and $418/MWh in NSW we are seeing this average drop each day.

The main driver for the lower spot prices is, as mentioned before, the improved availability across the NEM. Availability in QLD is regularly reaching 9,000MW compared to in June when it dropped 6,600MW. The short-term outlook for generation continues to improve daily with the majority of planned outages now completed.

A secondary driver that has pushed down average prices is the return of the sun. Solar generation is now regularly pushing the spot price below $100/MWh and on some occasions back into negative territory.

Less volatility in the spot market has been reflected in the forward market with Q422 QLD dropping from over $270/MWh in June to $260/MWh and the Q123 product dropping below $250/MWh.

Without delving into the gas supply concerns in Victoria, all other states have removed the price cap on gas allowing the market to operate more efficiently. This has not resulted in the gas market trading at significantly high prices as feared, Qld is $42.75/GJ, NSW is $51.51/GJ and SA at $45.51, translating into a sub $500/MWh peaking gas plant cost of generation.

As the weather warms up and the daylight hours increase, we expect to see a drop in demand, with heating loads reducing coupled with an increase in the generation provided by solar.

All of this, as well as increased thermal generator availability and stability in the gas markets, should see spot and forward prices continue to fall across the quarter.

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

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.