AEMC Reliability Panel Stakeholder Input

On December 12th, the AEMC released a request for stakeholder input as it commenced its System Restart panel review.

The panel are looking to review the challenges, especially around:

  • The increasing reliance on the lowered availability of System Restart Ancillary Services (SRAS) and scarcity of that capability from new transmission-connected generators.
  • The rising system restoration risks are coming about within areas of large penetration of distribution-connected PV generation.

The framework is being assessed in two stages: the first comprises a review to assess whether the current regulatory framework suits the evolving nature of the grid under the AEMO ISP, and the second revises the requirements around system restarts based on the first stage findings, considering the risks associated with major supply disruption risks and SRAR availability and costs.

In the event of a significant loss of generation and supply to consumer load, the current arrangements allow for invoking the SRAS procedures known as black start capability. This capability is usually made up of smaller, quick-to-start, smaller-generation units that can assist historically large baseload units in coming online.

Overall, the absence of this generation would primarily become problematic during a large-scale system failure, similar to the issues experienced with Callide. However, as we transition to a grid with more variable generation and fewer synchronous units, such disturbances could become more frequent. This trend may persist until sufficient storage capacity is available to stabilise the system.

Submissions close on 30/01/25, and it is likely that a significant number of differing opinions will emerge as businesses advocate for ensuring payments are available for these events. This could also strengthen the arguments being presented, following the ESB Post 25 assessment, for the introduction of a capacity mechanism for generators on the NEM.

Record demand recorded in Queensland

Queensland set a new record for operational demand on January 22, 2025, exactly one year after the previous record on January 22, 2024. The demand reached 11,144 MW, surpassing last year’s record of 11,005 MW.

This high demand was driven by extreme heat and associated cooling loads, significantly exceeding forecasts. Evening demand surpassed the 10% Probability of Exceedance (POE10) forecast of approximately 10.7 GW by about 0.5 GW. Similar to last year, the POE10 forecast underestimated demand, then by about 0.3–0.4 GW.

The unexpectedly high demand strained the Queensland grid, causing significant market volatility. The daily average electricity price spiked to $1,133/MWh, increasing the Q1 2025 quarterly average by approximately $45/MWh.

The situation was exacerbated by the Gladstone 2 unit tripping just before 7 PM, although it returned to service around 1 AM the next morning. Limited interconnector flows from New South Wales into Queensland, caused by constraints and ongoing issues at Bayswater 2, further compounded the problem.

Queensland is expected to see softer electricity demand in the coming week as temperatures are forecasted to decrease.

In contrast, New South Wales’ POE10 forecast is 12.8 GW tonight, driven by high temperatures across the state. While current pre-dispatch prices remain soft, such high demand means any outages or constraints could significantly impact spot prices and cause volatility.

As demand continues to rise year-on-year, concerns about supply adequacy during the energy transition are growing. Are these trends and risks adequately accounted for in future forecasts? Will supply keep pace with demand?

Looking ahead, could February 2025 bring further record-breaking demand events?

Trump’s inauguration and impact on energy

Donald Trump will officially become the 47th President of the United States at noon on Monday, January 20. With Trump’s inauguration, several decisions could have a global ripple effect on energy policy. Edge2020 highlights key changes that may shape the landscape heading into 2025.

Withdrawal from the Paris Agreement

There is anticipation that Trump could direct the U.S. to withdraw again from the 2015 Paris Agreement, as he did during his first term.

The Paris Agreement is a global pact to combat climate change by reducing fossil fuel emissions and limiting forecasted temperature increases.

The U.S., as the largest historical emitter of greenhouse gases, is a key player in driving global climate efforts. Therefore, its withdrawal could be significant.

Increase in Gas and Oil

Trump plans to lift the moratorium on new LNG export permits imposed by Joe Biden’s administration in early 2024. The moratorium was introduced to allow a study on the environmental and economic impacts of rising U.S. gas exports, which surged as the Russia-Ukraine war prompted many countries to cut imports of Russian gas.

In addition to this, Trump is anticipated to increase oil and gas drilling within the U.S., reversing Biden’s attempt to reduce fossil fuel development on U.S. acreage.

This will be subject to the discretion of his administration to determine which acreage will be offered for auction to drillers. Biden’s recent use of the Lands Act to protect areas various areas in the Atlantic and Pacific will pose challenges in expanding offshore drilling.

Offshore Wind

Trump has expressed his intention to stop new offshore wind developments, citing concerns in regards to cost, its potential impact on whale populations, and the waste generated by decommissioned turbines.

The offshore wind industry in the U.S. is already facing significant challenges with rising costs and supply chain issues.

Tariffs

Trump has promised to impose tariffs on various U.S. imports, including Canadian crude oil, as well as parts for solar and electric vehicle batteries. The impact of these tariffs will depend on the specific details of their implementation.

National Emergency for Energy

Trump may declare a national energy emergency upon taking office, following statements made during his campaign last August, where he pledged to reduce electricity and gas prices. This would allow him to fast-track permits for new infrastructure and other energy projects. This includes projects within industries such as natural gas, renewables, pipeline operators, and nuclear.

This move aligns with his broader agenda to expand energy production in preparation for the anticipated increase in demand from data centres.

Donald Trump’s inauguration as the 47th U.S. President marks a major shift in energy policy. Plans to boost oil, gas, and LNG production, withdraw from the Paris Agreement, halt offshore wind projects, and impose tariffs could reshape global energy dynamics.

How might these policy changes, if implemented, shape the future of energy?

December 2024 Gas Inquiry Report Recap

The December 2024 Gas inquiry report by the ACCC was released on Friday, with its focus on the operation of the east coast gas market.

Natural gas is vital to Australia’s transition to lower emissions, supporting energy security, reliability, and affordability as renewables dominate electricity generation. It remains essential for all users including residential, commercial, and industrial users, particularly for manufacturing and chemical processes where alternatives are not viable such as electricity.

However, east coast gas supply is declining as traditional sources like the Gippsland Basin begin to deplete and new investment lags behind. In the short term, southern states are forecasted to rely upon gas transported from Queensland, facing constraints in pipeline capacity and potential dependence on imported LNG. This will increasingly tie domestic gas prices to international markets and transportation costs, driving up prices locally.

The 2022 energy crisis underscored the risks of inadequate gas supply and the market’s susceptibility to global volatility. To ensure reliability and a smooth transition to lower emissions, the east coast gas market must remain well-supplied as demand for gas is expected to remain high for at least two decades. While residential and commercial demand may decline with electrification, industrial demand will persist due to the lack of alternatives.

AEMO has forecasted that gas-powered generation will grow, requiring additional infrastructure to fill the gap created by intermittent generation from sources like solar and wind until sufficient storage is developed. The ACCC also mentioned that declining residential demand may also impact gas distribution networks, raising concerns about stranded assets and potential costs for end users.

The report highlights the critical role of natural gas in Australia’s energy transition and warns of the challenges ahead. Declining east coast supply, rising reliance on imports, and links to volatile international markets risk driving up prices. This price increase would likely flow through to energy prices, impacting the southern states in particular. With gas-powered generation needed to fill the gaps of solar and wind, action is required to secure supply and invest in new infrastructure. Will the necessary steps be taken in time?

The role of Mount Piper

At Mount Piper Power Station, a coal power station near Lithgow in NSW, operators work to minimise financial losses by reducing the units minimum operational load at which the units can stay online, as electricity prices plummet into negative territory during solar hours, driven by an influx of solar generation flooding the grid. They focus on positioning the station to capitalise on the expected price spike later in the day, as solar generation declines and supply tightens, leading to higher prices.

The plant, which has a total capacity of 1430 MW, can still operate a little over 10% capacity. While it was initially able to ramp down to only 320 MW, its minimum operating level was reduced to 150 MW in July 2023. This approach enables the unit to operate at a reduced load during the day – despite incurring losses, before ramping up production during the evening peak to offset earlier deficits and achieve profitability. “It’s a balancing act – how hard do they need us to get out of the way [of cheap renewable energy] versus how hard do they need us in the evening,” said Steve Marshall, Head of Mount Piper for EnergyAustralia.

With a capacity of 1430 MW, the power station’s two turbines supply about 10% of NSW’s maximum demand.

Mount Piper was instrumental during two significant grid events throughout 2024: the pre-summer heatwave in late November and the administered pricing event in May, where blackouts were narrowly averted. During these critical periods, the station operated at full capacity. Without Mount Piper’s contribution, load shedding in parts of NSW would likely have been inevitable.

Mount Piper has proven to be a reliable and critical unit in the state, experiencing minimal unplanned outages or trips compared to other units in the NEM.

Mount Piper Power Station has also explored ways to better manage the impact of solar carveouts, trialling a process called ‘two-shifting.’ This involves taking one steam turbine off the grid for up to 12 hours while keeping the boiler warm and ready for a quick restart. This approach has been adopted in other regions, such as the United Kingdom and United States, where plants have adapted to different daily cycles. However, operating the units in this manner is expensive, as they require upgrades and/or increased maintenance.

Several coal units across the NEM have struck agreements with the government to ensure supply capacity remains available until their planned exit from the grid.

  • Yallourn Generator (VIC): Secured by a 2021 agreement with the state government, ensuring 1480MW capacity until mid-2028.
  • Loy Yang A Generator (VIC): Similar agreement extending operation until 2035.
  • Eraring Plant (NSW): Agreement with NSW government extends operation to August 2027, adding two more years, with the option for a further two years without subsidies at this stage.

Mount Piper Power Station plans to play a “reserve” role, functioning as a firming unit that runs only when necessary to fill gaps in wind and solar generation. For several years, the station has participated in discussions with the NSW government about a potential industry-wide coal closure plan. A bill to establish a framework for the “orderly exit management” of coal power plants was passed by South Australian parliament on Wednesday, 27 November 2024, though the rules are still being finalised.

Mount Piper’s low minimum running output and two-shifting capability position the station as a valuable asset in the energy transition. However, maintaining the flexibility comes at a considerable cost. A major maintenance overhaul, scheduled to commence in April 2025, will require an investment of $160 million. During this period, Unit 1 will be offline from April 1 to May 26, and Unit 2 from April 6 to April 27, resulting in a 21-day overlap when both units will be out of service.

Edge2020 anticipates Mount Piper Power Station to play an increasingly crucial role in the transition as new clean generation and transmission projects come online. Given the station’s growing financial challenges amid negative prices, volatile market demand, and stricter environmental and regulatory requirements, this shift will require significant policy support by government.

Increased Trading Volume of Electricity Options

Over the past 6 years, there has been a surge in trading volume of electricity options. Drivers for the increase can be primarily attributed to the increased presence of speculative trading firms within the electricity market attempting to manage and capitalise on the volatility within the market. Options are also becoming an increasingly popular tool in the electricity space given the increase in Power Purchase Agreements (PPAs) being underwritten by these products. In doing so, companies are hedging against potential downside movements in the market to become more risk averse.

This trend highlights a strategic shift towards using financial instruments to manage electricity positions and mitigate risks associated with these long-term contracts. However, the volume traded in May 2024 for FY25 options expiry indicates a deceleration in trading volumes.

Interestingly, the dynamics of the options market are similar in the larger states of the NEM: Queensland, New South Wales, and Victoria. However, this contrasts significantly with South Australia, where the volume of options traded is much more in line with the volume of Futures traded. Overall, the futures and options market in South Australia is highly illiquid, with trading volumes declining over recent years. With the recent Q1 in SA being under RRO conditions and therefore fully contracted, the likely need to have exposed positions underpinned in the state has reduced and with it the appetite for speculators in the market. This contrasts with the other NEM states whose interconnector flows allow for cross-border spreads to be contracted and the opportunity for speculators to take advantage of these financial products without the requirement to physically settle their positions.

Electricity options are primarily traded in financial year (FY) and calendar year (CAL) strips, expiring in May (for FY) and November (for CAL) each year. Significant spikes can be observed in the following graphs for Queensland, New South Wales, and Victoria. The first four graphs illustrate a rising trend in trade volume over time, followed by a noticeable decline in the most recent expiry in May. The subsequent four graphs (graphs 5-8) overlay the FY24 quarter’s price and volume, highlighting the timing of expiries and their potential impact on prices.

With the CAL products coming towards expiry in November and high prices remaining in the ASX Swap market, this will likely lead to many of these products being exercised at expiry due to the strike price likely being below the current forward price. This can lead to increased volatility on the ASX over these periods and significant volume being traded. What will add a level of interest in this particular expiry period will be the low generation availability in NSW at the time of expiry. With many units already on outage schedules, any unplanned outages on the system could further exacerbate the price and add a level of fear and uncertainty to the market.

Graph 1 – NSW Trade Volume

Graph 2 – QLD Trade Volume


Graph 3 – SA Trade Volume

Graph 4 – VIC Trade Volume

Graph 5 – NSW FY24 Trade Volume & Price

Graph 6 – QLD FY24 Trade Volume & Price

Graph 7 – SA FY24 Trade Volume & Price

Graph 8 – VIC FY24 Trade Volume & Price

Are there seasonal trends in the FCAS market?

Edge have investigated seasonal trends from FCAS cumulative costs, specifically with regards to lower FCAS. Raise FCAS charges are paid by the causer (generator), and lower FCAS charges are paid for by the consumer.

Firstly, considering the raw data, we can observe that there does appear to have been some increase in total FCAS charges by year, however specifically, we can see that these mostly come in large spikes in one state’s FCAS charges in a specific month, as opposed to all states growing proportionally.

Excluding the monthly breakdown, the data shows FCAS charges growing from 2018 to 2022, with a reduction in 2023. Notably, the summer of 2024 and the December 2023 period were under the RRO in SA, and the summer was notably mild compared to forecasted conditions, which may have impacted FCAS pricing during that period.

An analysis of the monthly data reveals state-specific seasonal trends, occasionally disrupted by anomalies or significant events. Analysing the monthly patterns for each state reveals the following seasonal effects:

In New South Wales, FCAS charges are typically lower in the winter, increasing from August to January before declining.

In Queensland, FCAS charges primarily occur from August to November, though Queensland remains highly reactive, with spikes in March and May reflecting this behaviour.

South Australia reflects behaviours from both New South Wales and Queensland, where FCAS charges rise post-winter and through spring, with significant spikes in 2020 and 2019 elevating the averages for February and November, respectively.

Tasmania has no obvious seasonal effects observed with prices remaining relatively consistent throughout the year.

Victoria mimics behaviours similar to New South Wales, with low FCAS charges in winter, increasing from August to January before declining.

Depending on the state, strategies could be developed to proactively lower FCAS charges, particularly in response to sudden frequency deviations over short periods. Energy users can deploy onsite batteries or demand side response abilities, that discharge during periods of high FCAS pricing to provide spontaneous services.

The highest payout services are predominantly Lower slow 60sec and Lower fast 6sec, which require batteries capable of responding within the specified 60-second and 6-second windows. While there is a very fast FCAS market (1-second raise / lower), this market is currently used less compared to the standard 6/60-seconds markets.

Queensland Operational Demand Records

In 2024, Queensland has experienced extreme fluctuations of operational demand, reflecting the complexities of the ongoing energy transition. From record high demand peaks in January surpassing 11GW, to unprecedented lows in August below 3GW, the Queensland grid has been stretched in both directions, highlighting the challenges of integrating renewable energy sources into a grid previously dominated by fossil fuel baseload.

On 22 January, Queensland recorded an all-time maximum demand exceeding 11,000MW, smashing the previous record by approximately 800MW. This surge in demand was driven by very hot and humid weather, leading to a substantial increase in cooling loads across the state.

In stark contrast, on 18 August, Queensland registered its lowest operational demand in at least 24 years, dropping to 2,975MW. This significant dip was primarily due to the increased penetration of rooftop solar, which contributed an estimated 3.8 to 3.9GW of electricity during this period. With such a large portion of the state’s power being generated by rooftop solar, electricity prices during daylight hours plummeted.

However, this record low demand driven by solar, resulted in approximately 1.8GW of variable renewable energy (VRE), predominantly from solar, being curtailed during this period. This only left 745MW of utility scale solar feeding into the grid. This level of curtailment underscores the growing challenge of balancing the supply and demand of renewable energy, particularly as rooftop solar continues to expand while storage solutions lag behind.

The previous low demand record was set in October 2023 at just over 3GW. As we approach September and October of this year, there is anticipation that demand could drop even further as traditionally this is the lowest period for demand. However, this will depend on factors such as luminosity, rooftop PV generation, and temperature, potentially leading to reduced electricity prices and increased curtailment.

This situation also raises concerns about the oversupply of solar energy and the urgent need for further investment in grid infrastructure and storage solutions required to manage these fluctuations.

One of the most significant issues facing the broader market is the impact of rooftop solar PV, which operates outside the traditional market, causing electricity prices to crash during sunny hours. This, in turn, pushes out utility scale solar and other sources of generation, presenting a challenging issue going forward of managing different types of renewables and preventing them from significantly cutting into each other resulting in curtailment.

Tightening in the ACCU Market

Person using a laptop with carbon credit and sustainability icons floating above their hands, including CO2, recycling, solar energy, and net zero symbols.

The Department of Climate Change, Energy, the Environment and Water (DCCEEW) intends to stop the development of the Integrated Farm and Land Management (IFLM) method.

The reasoning is due to difficulties demonstrating the environmental benefits of regeneration activities in areas not previously cleared. Instead, the DCCEEW has proposed a new system to be developed, the Landscape Restoration Method (LRM), which considerably tightens grazing activities compared to the previous Human Induced Regeneration (HIR) method.

As a result, the market responded to the news with increased activity for HIR ACCUs and price firming for both generic and HIR ACCUs. The generic ACCU market has firmed since late last year, increasing from the $31-$32 range to $36.

Depending on the scope of allowed grazing activities under the future IFLM or IRM, the market could significantly move. The IFLM method was initially expected to fill the supply gap created after the retirement of two major methods by the end of 2024.

The ACCU market is currently priced to increase into the future, with a cost of carry of ~7%. This is ultimately driven by demand from safeguard participants and some voluntary demand associated with sustainability targets.

The current baselines decrease by 4.9% each financial year out to 2030, with an emission reduction contribution of 65.7% in 2030. The demand for ACCUs to offset organisations’ emissions is anticipated to surpass ACCU issuance for the first time in 2028. The high demand and low issuance are currently forecasted to continue until 2031, where demand for ACCUs is forecasted to peak at 31 million certificates. This is significantly up from 2022, where demand from scheme participants was less than 1 million. However, facilities that are covered by the Safeguard Mechanism are able to generate SMCs, which are a new type of credit issued as a reward for emitting below one’s limits, which could ease overall demand on ACCUs.

The Australian Government has made ACCUs available to liable entities at $75/cert, increasing with CPI plus 2%, ultimately setting a price cap for them. In future years, when supply and demand become tighter, could we witness an ACCU market consistently trading at or near the cap, similar to the current STC market?

The Importance of Eraring and Ongoing Negotiations

Aerial view of a coal-fired power station with tall chimneys emitting smoke, surrounded by forest and a body of water in the distance.

Eraring, which is forecasted to close in August 2025, has highlighted its necessity to stay online by playing a vital role in the NSW grid. This was demonstrated on February 29 during high temperatures, where demand exceeded 13GW, reaching the highest level since February 2020. During this period of high demand, electricity prices soared towards the market cap of $16,600 and remained volatile for over an hour, adding approximately $13/MWh to the quarterly average to date. Eraring was supplying up to 16.5% (or 2.2GW) of the state’s power during this period.

Without this generation, the state likely would have enacted RERT or possibly load shedding to ensure grid stability, further adding pressure to keep the unit online until there is ample renewable generation and storage to cover the capacity leaving the grid.

Origin stated that Eraring operated as normal on February 29, which “performed well to meet customer needs and support the market”. However, there is a lot of uncertainty and nervousness around the retirement of coal power plants in the NEM, which need to be replaced by clean energy, and the new transmission lines required to connect them to the grid. These are faced challenges such as planned delays, community opposition, and rising costs.

Negotiations between Origin Energy and the state government about keeping it on have been dragging on for about six months now. Origin is seeking a safety net to avoid losses associated with keeping the unit online. However, NSW Treasurer Daniel Mookhey said on Wednesday that the negotiations about keeping Eraring open were “not an opportunity for Origin to make a windfall gain at the public’s expense”.

The two main issues that will affect the cost of Eraring operating post its original closure are onsite ash dam storage issues and no current coal contracts past its closure. Eraring’s ash dam storage is currently at capacity, and as a result, will need to ship ash waste offsite in the future. Additionally, Eraring has no long-term coal contracts post its closure, as a result, Eraring will have to enter into a coal contract at a higher price as coal has significantly increased in recent years. Depending on whether the government subsidizes this cost, Eraring’s running cost could increase significantly, therefore lifting the market significantly due to Eraring’s size and role in the NSW grid.