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.

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.

Progress of Snowy 2.0

Active construction site of Snowy 2.0 hydroelectric project with cranes and temporary buildings on a rugged landscape.

Since the beginning of construction, Snowy 2.0, a pumped storage power station, has faced a variety of challenges and issues, including the tunnel boring machine getting stuck late 2022 and the project being well over budget, more than double the previous estimate, and six times the ballpark figure given by Malcolm Turnbull.

Despite these setbacks, rock conditions are currently good, and in a year’s time, the project is forecasted to have created an underground cavern that should be big enough to accommodate a 22-story building. This will house the $12b 2.2GW system with a storage capacity of 350,000MWh (159 hours at full power), which is forecasted to reach full commercial operation by December 2028.

Snowy Hydro CEO Dennis Barnes stated they are approximately 51% of the way to completing the project, but there is still a lot to de-risk going forward.

The tunnel boring machine Florence, which got stuck in September 2022 due to unexpected soft ground, was stuck only 140 metres into its 16-kilometre journey. Florence has begun to move again in December 2023, but moving at a rate of 6 metres per day. In order to stay on target, Florence will need to pick up the pace to 12 to 15 metres a day.

According to Barnes, Snowy is considering a fourth boring machine to ensure the project will keep on the revised target, with the decision being made in the following months.

Projects such as Snowy 2.0 providing long-term storage are crucial for the energy transition in the NEM, being able to provide firming capacity during solar and wind droughts, which will inevitably occur. This will allow for the retirement of coal units, as well as allow for a total of 6.6GW of new renewables into the system.

Even with the need for such projects, the project has faced backlash due to the cost blowing out considerably higher than initial estimates, particularly when the additional $8.5 billion of connecting transmission to the north and south is included.

Despite the range of challenges faced by Snowy 2.0, including budget blowouts, difficulties with the tunnel boring machine, and delays, the project is showing progress and plays a key role in achieving Australia’s renewable energy targets.

 

Callide Legal Action and Regulatory Challenges

Safety worker in hard hat pointing at electrical transmission towers under a colorful sunset sky, highlighting energy infrastructure.

Callide is facing increased scrutiny as the Australian Energy Regulator (AER) is taking legal proceedings against Callide Power Trading due to an explosion at Callide C. In May 2021, an explosion at Callide C4 led to the tripping of multiple generators and high-voltage lines in Queensland, leaving nearly half a million homes to lose power.

The AER alleges that Callide Power Trading broke the National Electricity Rules (NER) by not adhering to its own performance standards for Callide C4. According to the allegations, the C4 unit lacked a protection system in place or having sufficient energy supply to suddenly disconnect the unit when the explosion occurred.

Justin Oliver, an AER board member stated that “Failure to comply with these standards can risk power system security, see consumers disconnected from power supply and cause wholesale energy prices to increase during and beyond these events”.

Callide C3 is expected to fully return on March 31st, with C4 following on July 31st. These are revised dates following various delays affecting both units.

In a separate incident, the Federal Court ordered IG Power, who owns 50% of Callide to appoint special administrators with powers to complete a new investigator into the incidents at the power station.

There is currently no date set for the AER’s matter to be heard at Federal Court.

This highlights the immense pressure on the energy industry and regulation to suppress spot prices in the NEM. This pressure has come in various forms including market directions, price caps on underlying fuel sources such as coal and gas, and retailer reliability obligation (RRO) being enacted in SA this summer.

This pressure has been evident in the spot price, as the spot price over the summer has been very soft, particularly in South Australia and Victoria, with prices being far below forecasted and previously traded levels.

This has caused issues for generators leading Engie to announce the early closure of two units in SA, removing 138MW of capacity from July 1, brought forward from an initial closure scheduled for 2028. This is due to financial reasons as losses have been mounting at the plants, unable to make a profit in the spot market.

There is currently a T-3 forecasted in South Australia from December 2025 to February 2026. Following the recent RRO witnessed over the summer in South Australia where spot prices have been low, volatility has been minimal, and there have been few system security issues in the state. Will we see any revisions or changes to RRO in the future?

Potential for Below Baseline REGOs

Two silhouetted figures stand on a platform at sea, observing a vast offshore wind farm against a dramatic sunset sky.

LGCs are now in an interesting position. With the REGO scheme all but fully legislated to start in 2025, there may be opportunity to meet voluntary requirements from this secondary market before it becomes the likely primary market at the end of 2030 until 2050.

The REGO scheme looks likely to exist in parallel to the LGC scheme until the expiry of the RET, with generators able to decide which products they would like to produce in any given period.

However, the REGO scheme will open previously un-tapped generation, such as below baseline generation, generation from outside of the Australian economic waters area and exported generation i.e. Sun Cable, which the LGC cannot. Further (although unlikely before 2030), STCs can be pooled to create 1 MWh, i.e. 1 REGO certificate at the point the 1MWh limit is reached.

This market is currently untapped, but with a REGO holding the same credentials as an LGC, the voluntary surrender optionality (RET Liability must still be met with LGCs until 2030) can be achieved through the REGO scheme.

With voluntary surrenders increasing, the CER estimated in 2022 a total of 7.4million LGCs were surrendered voluntarily. This increased the demand for LGCs by 1.6million in comparison to 2021 and created a demand 23% above the legislated requirements for LGCs (33m).

Prior to a REGO scheme, the increasing demand for these LGCs has come from growing corporate targets either directly into the LGC market or through its secondary market, such as GreenPower schemes.

Without increasing the availability of alternative generation sources, this growth could lead to a tightening of the supply-demand balance of the LGC and an increase in price. As such the introduction of a REGO from 2025 could be the pressure release valve the industry requires.

The growing non-RET requirements are significant, and therefore, the introduction of secondary sources of power through the REGO scheme is the only way the market will be able to meet the increasing demand.

The ACCC investigation into Momentum in 2016, where Momentum was handed a $54,000 fine for falsely advertising their green credentials, as they are backed by Hydro Tas whose generation was below baseline, has brought to the fore the requirement for accreditation of these below baseline assets (outside of the i-REC scheme).

Below baseline is renewable generation assets created before 1997 – mainly hydro assets. The baseline is set on production between 1994 – 1996, and therefore, generators coming on from 1997 have a baseline of zero and can produce LGCs, unlike those online prior to 1997. Indications are these facilities generate 12-13TWh of electricity each, that is, 12-13 million REGOs, which could come into the Australian voluntary market (pre-2030 RET end). However, the below baseline generation is eligible for an i-REC certification and many assets pursued this option prior to the REGO /GO scheme announcements. As such, this 12-13 million may be as low as 2 million in the initial years, given existing PPAs and voluntary i-REC surrender deals in place.

It is worth noting, if Hydro Tas had created the REGO and these were surrendered against the Momentum portfolio, the renewable claim would have been upheld, and the REGO would have never hit the market. This example shows that even if produced, companies may utilise the additional certification without giving others the opportunity to trade them in the open market.

A concern does sit around the inclusion of small-scale renewable REGOs, although unlikely to be in large quantities prior to 2030, the concern holds that the measurement of the “hour” the REGO is produced, when the cumulative units have reached 1MWh of generation, is currently untested and there are a significantly larger number of these units than there are utility scale solar. The cost and oversight required could add cost to the certificate, which we currently have no view of as to the uptake or requirements.

AEMO’s Draft 2024 Integrated System Plan

Electricity substation at sunrise, representing the transition in Australia's National Electricity Market as per AEMO's 2024 ISP.

AEMO recently released its Draft 2024 Integrated System Plan (ISP), which serves as a roadmap for the energy transition in the National Electricity Market (NEM) over the next 20-plus years in line with government policies aimed at achieving net zero by the year 2050.

The plan outlines a cost-effective strategy for essential energy infrastructure to meet consumer needs, ensure reliability and affordability, and achieve net zero. AEMO highlights the urgency for action as the NEM shifts from coal-fired generation dependency. With the closure of coal-fired power stations, the draft proposes using renewable energy supported by storage and gas as the most economical solution for Australia’s energy transition.

The policy set by the Federal Government aims for a 43% reduction in emissions compared to 2005 levels by the year 2030. Additionally, the policy targets 82% of electricity supplied in the NEM to come from renewable sources.

Previous ISPs established ambitious trajectories for investment, and it is imperative that projects are now executed according to the plans. AEMO’s most probable future scenario predicts about 90% of NEM’s coal fleet will retire before 2025, and the entire fleet will retire before 2040.

The energy transition is already well underway, with coal retiring faster than initially announced. The ISP continues to stress the need for urgent investments in generation, firming, and transmission to maintain a secure, reliable, and affordable electricity supply. The retirement of coal-fired generators necessitates a transition to low-cost renewable energy, supported by firming technologies like storage and gas-powered generation.

AEMO has stated that the NEM must almost triple its capacity to supply energy by 2050 to replace retiring coal capacity and meet increasing electricity demand. Every government within the NEM is actively endorsing the transition. The Federal Government has broadened the Capacity Investment Scheme, while various states have their initiatives supporting the transition to net zero.

The 2024 ISP outlined three future scenarios for 2050, which included Step Change, Progressive Change, and Green Energy Exports. All these scenarios involve the retirement of coal, aligning with government net-zero commitments. AEMO has assigned likelihoods of 43% for Step Change, 42% for Progressive Change, and 15% for Green Energy Exports.

Under AEMO’s optimal development path (ODP) for the Step Change scenario, there is a call for investment that would triple grid-scale variable renewable energy by 2030 and increase it sevenfold by 2050. The plan emphasises grid-scale generation within Renewable Energy Zones, quadrupling firming capacity, supporting a four-fold increase in rooftop solar capacity, and leveraging system security services to ensure reliability.

In terms of transmission, nearly 10,000 km of transmission is needed by 2050 for the Step Change and Progressive Change scenarios, with over twice that to support the Green Energy Exports scenario. The annualised capital cost for all infrastructure in the ODP until 2050 is $121 billion, with transmission projects constituting 13.5% of the annualised cost.

The NEM faces several risks in transitioning from coal to renewable energy. Key challenges that AEMO has identified include uncertainty in infrastructure investment, early coal retirements, markets and power system operations that are not yet ready for 100% renewables. Additionally, consumer energy resources are not adequately integrated into grid operations, the social license for the energy transition is not being earned, and critical energy assets and skilled workforces are not being secured.

In summary, AEMO’s Draft 2024 Integrated System Plan charts a crucial path for Australia’s energy transition, aligning with net-zero goals. With an urgent focus on retiring coal-fired stations, the plan advocates a swift move to renewables backed by storage and gas solutions. The plan also outlines the significant challenges faced by the industry that are required to be overcome in order to reach net zero by 2050 while ensuring a reliable and affordable energy supply.

Threats to Gas Supply Deal

Aerial view of an LNG tanker docked at a coastal industrial facility with distinctive spherical storage tanks and infrastructure for natural gas.

Chris Bowen, the Energy and Climate Change minister, announced a plan to address looming supply issues for east coast homes and businesses by securing commitment from two big gas exporters (APLNG and Senex) to divert 300 petajoules of gas into the east coast domestic market by 2023. This amount is equivalent to about half of the annual East Coast domestic market demand or two years’ worth of industrial usage.

However, this new deal is already under threat from the Greens, who plan to challenge the government’s industry code of conduct in parliament. Should the coalition support the Greens’ motion, the deal could fall through, increasing the risk of gas supply shortages in the future.

The deal gives exemptions to APLNG and Senex from the $12/GJ price cap under the code of conduct. Chris Bowen stated that “This supply is critical for households, industry and gas power generation as the Bass Strait fields deplete”.

The gas price cap was introduced by the government last year, which triggered a freeze in new supply investments. After negotiations, the government revised the code of conduct, allowing exemptions for gas developers who committed to selling into the domestic market. Bowen has criticised the Greens for potentially disrupting the deal, highlighting the critical role gas will play in the energy transition and for grid reliability.

In related news, Australia’s annual climate change statement projects emissions to be 42% below 2005 levels by 2030, slightly below Labor’s election commitment of 43%.

Additionally, Chris Bowen has declined to specify the potential financial impact on taxpayers from the newly expanded Capacity Investment Scheme. The scheme involves the Australian government underwriting 32GW of new power generation through two auctions per year.

While industry experts anticipate this could cost billions annually, Bowen stated, “It is quite standard budget treatment to say we will not indicate our pricing expectations as we’re about to enter an auction”. He assured that the government’s strategy aims to maximise taxpayer benefits and maintain competitive bidding.

The scheme does not intend to “subsidising negative pricing”. Instead, it requires project proponents to state their minimum required profit and a maximum price point for sharing profits with the government. The government will retain control over bid acceptance and the total amount of gigawatts allocated.

AEMO’s Summer Readiness Briefing

Close-up of a document with the term 'El Niño' highlighted in pink.

On Monday the 13th, AEMO held their annual Summer Readiness briefing. The purpose of this report is to highlight risks and address how they will be combatted in the upcoming summer. The report highlights the well-known risks of El Niño, such as extreme peak demand due to heat (potential for POE10), and the potential for reduced wind generation. In addition to the following covered within the briefing:

  • Weather & Climate outlook
  • Electricity & Gas System Readiness
  • Network Readiness
  • Victorian Bushfire Readiness

The briefing also noted that scheduled generation availability is up across all states compared to last summer, it also points out the risk that several generators are on longer-term outages in the November–December period. Specifically, in coal generation, the following outages were highlighted:

  • QLD: Callide B1/B2, C3/C4, Gladstone 1/2, and Tarong 4
  • NSW: Bayswater 1, Eraring 2
  • VIC: Loy Yang A2, Newport, Yallourn 2

The report highlighted the effects of the positive El Niño, combined with a positive Indian Ocean Dipole (IOD) which would amplify the effects of the El Niño. The El Niño is currently expected to persist into Autumn with the positive IOD forecasted to last into at least early summer.

Additionally, there is also a number of planned high-impact network outages scheduled for the summer. However, AEMO highlights that these outages are only allowed to proceed if they do not pose any system security issues.

TransGrid presented a Bushfire Risk Management Plan which outlined the proactively management and mitigation of our exposure to bushfires. This includes risk of bushfires affecting transmission lines. Proactive management and mitigation involved vegetation management and identifying any high priority defects prior to the start of the season. Ultimately, TransGrid’s assessment indicated strong organisational preparedness for the 2023/24 bushfire season.

The report also notes needed increases in Reliability Emergency Reserve Trader (RERT) participants, specifically to the reliability gap outlined in the latest ESOO (118MW and 120MW in SA and Vic respectively).