Will geopolitics derail electricity price falls?

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

Overview

On 19 March 2026, the Australian Energy Regulator (AER) released its Draft Default Market Offer (DMO) determination for the 2026–27 regulatory year. The Draft DMO proposes electricity price reductions across all DMO regions (NSW, Southeast QLD, SA). The DMO establishes a regulated price cap for standing offer electricity plans and serves as a benchmark reference price for market offers. It is designed to provide a safety net for households and small business customers who do not actively switch electricity retailers.

Under the Draft determination, residential customers are forecast to experience annual price reductions of between 1.3% and 10.1%, while small business customers could see larger reductions ranging from 7.6% to 21.2%, depending on region and distribution network. These reductions are primarily driven by lower wholesale electricity costs (WEC).

Wholesale Electricity Costs and DMO Methodology

Wholesale electricity costs are a key component of the DMO and are calculated using a complex methodology. In simplified terms, the WEC reflects a volume-weighted average of ASX Energy contract prices. As WEC typically represents approximately 30–40% of the final DMO, changes in forward contract prices can materially influence regulated electricity prices.

Lessons from the 2022 DMO Volatility

Historical experience demonstrates the sensitivity of the DMO to rapid changes in energy contract prices. In 2022, a sharp increase in futures contract prices—approximately 100% between the Draft DMO release in February and the Final DMO determination in May—was largely triggered by the war in Ukraine. This resulted in a significant uplift in WEC, with increases of ~25% in QLD and NSW, and ~5% in SA.

The table below illustrates the extent of these changes in 2022 for flat-rate tariffs across key distribution networks:

Distribution Network Draft WEC ($/MWh) Final WEC ($/MWh) Change
Ausgrid 97.94 122.23 25%
Endeavour 98.94 124.25 26%
Essential 91.53 115.97 27%
Energex 92.47 110.53 20%
SAPN 128.26 134.53 5%

 

Current Market Conditions and the Iran Conflict

Baseload quarterly contracts for FY27 remained broadly stable throughout most of 2025 and declined steadily between November 2025 and February 2026. However, following the US–Iran conflict on 28 February 2026, contract prices across these three states have increased by ~10–20%.

This development raises the question of whether current geopolitical tensions could result in a similar divergence between the Draft and Final DMO outcomes as observed in 2022.

Expected Impact on the Final 2026–27 DMO

Analysis conducted by Edge2020, drawing on historical Draft versus Final DMO outcomes and movements in contract prices, suggests that if forward prices for FY27 remain at current levels, the impact on the Final DMO is likely to be minimal.

In a more extreme scenario—where contract prices rise rapidly over the next two months in a manner comparable to 2022—the WEC component could increase by up to 7%. However, such an outcome is considered highly unlikely due to stronger coal fleet availability, softer fuel prices, and increased renewable generation and storage capacity in the market. Even in this scenario, the overall impact on final DMO prices would be moderated, given the partial contribution of WEC to total DMO costs.

Longer-Term Implications

While the immediate impact on the 2026–27 Final DMO is expected to be limited, sustained higher forward contract prices would eventually feed into future DMO determinations. As a result, prolonged geopolitical instability and persistently elevated energy prices could place upward pressure on regulated electricity prices in subsequent years.

 

AEMC Confirms Higher Market Price Cap for FY27, with the Cumulative Price Threshold to Rise from July 2026

AEMC Publishes their Increase to NEM Reliability Settings for FY27

On 26 February, the Australian Energy Market Commission (AEMC) published its annual update to the National Electricity Market’s (NEM) reliability settings, confirming that the Market Price Cap (MPC) will rise from $20,300/MWh in FY26 to $23,200/MWh for FY27.

The Cumulative Price Threshold (CPT) will also increase to $2,225,900/MWh from 1 July 2026.

What Do These Changes Mean?

The Market Price Cap (MPC) is the maximum price that can be reached on the spot market during any dispatch and trading interval.

The Cumulative Price Threshold (CPT) is a safeguard mechanism. It acts as a trigger to end a sustained seven-day period of extremely high prices in the wholesale electricity market.

Under the new settings, the CPT will be breached if:

  • The spot price reaches the MPC for 96 five-minute intervals (8 hours), or

  • The spot price averages $1,104/MWh over a week,

When this occurs, the Administered Price Cap (APC) is triggered, capping wholesale electricity prices at $600/MWh. The APC remains in place for subsequent days if the CPT continues to be exceeded.

Why These Settings Matter

The NEM is an energy-only market, meaning generators are paid only for the electricity they produce, not for maintaining available capacity.

These price settings — which remain the highest price caps in the world — have no impact on wholesale electricity prices more than 99% of the time. However, they play a critical role during periods of tight supply by:

  • Encouraging additional generation into the market

  • Supporting system reliability during supply shortages

  • Providing incentives for investment in dispatchable capacity

In short, the MPC and CPT settings are designed to ensure supply is available when the system needs it most.

Risk Implications for Spot-Exposed Consumers

While high-price events are infrequent, their impact can be material.

Under the new MPC, a single five-minute interval at the MPC can increase the quarterly average spot price by approximately $0.90/MWh. This presents a meaningful risk for consumers exposed to spot pricing.

So far in FY26, the spot price has reached the MPC:

  • 6 times in NSW

  • 5 times in South Australia

  • 2 times in Tasmania

As volatility events become more common during periods of system stress, understanding exposure to high-price risk remains critical for energy users.

If you’d like to gain insight into how you can manage volatility under the new settings, please get in touch with our team at Edge2020.

The Woe of Callide

The woes at Callide Power Station continue to deepen and have claimed yet another casualty.

Sources indicate that on 4 April, a significant clinker (a mass of hardened ash) detached from the boiler wall in the C3 unit. While clinker formation is not unusual in coal fired power stations, routine maintenance typically addresses such issues during outages. It appears that this clinker broke away during the unit’s operation, causing the ash conveyor water system to release high pressure steam into the boiler.

It has also been reported that the steam from the ash conveyor water system subsequently extinguished the fires in all four mills, which process coal into pulverised fuel (PF) to fire the boilers. As a result, the boiler flames in the four mills were snuffed out, and the unit experienced a pressure fluctuation as it drew in unburned fuel and air. This fluctuation allegedly led to an explosion that caused extensive damage to the unit and its boiler.

Fortunately, no workers were in the vicinity at the time. However, significant repair work is now required, including in the hard-to-reach upper sections of the boiler, where extensive cladding and lagging repairs must be undertaken.

The political fallout continues to swirl. CS Energy CEO Darren Busine has already tendered his resignation, which has now been made immediate. There is also speculation that the General Manager of Callide Power Station has offered their immediate resignation.

Concerns have arisen around the LNP Queensland Government, specifically regarding what David Janetzki knew and when he knew it, particularly given his 8 April address to the Queensland Energy Club. In that speech, he announced coal and Callide would continue to play an ongoing role in Queensland’s energy mix beyond Callide B’s expected 2028 closure (at least another three years) with no mention of the recent explosion or the seriousness of the incident.

This event evokes memories of the Callide C4 explosion in May 2021, whose outcomes were finalised in February 2025 when the Australian Energy Regulator (AER) imposed a $9 million fine plus court costs on the joint venture for the Callide C4 unit. The fine, just shy of the maximum $10 million possible, was the highest ever imposed for failure to comply with performance standards under the National Electricity Rules (NER). The retailer was found to have breached the NER by failing to meet its own performance standards, and investigations revealed that there was insufficient energy supply to safely disconnect the generating unit when the explosion occurred. Furthermore, the protection systems intended to override the connections were found to be inadequate.

The incident report also noted that, two minutes after staff evacuated due to a fire, a two-tonne rotor shaft piece was thrown five metres across the turbine hall floor, while a 300kg piece of equipment was hurled 20 metres into the air, breaking through the hall’s roof.

Gas Statement of Opportunity

After years of the government placing their heads in the sand on the East Coast Gas Crisis, which is about to engulf the Australian market, the Gas Statement of Opportunities (GSOO) and the government are finally recognising that the status quo will no longer work.

AEMO’s CEO, Daniel Westerman, has emphasised the severity of the situation, noting that the Longford plant is set to retire in 2033 and will likely see reductions leading up to that point. Longford supplies two-thirds of the East Coast gas supply, and with Bass Strait fields depleting and coal closures imminent, new investment in gas supply is imperative.

The gas gap, the difference between supply and demand, remains from 2028/2029, making investment decisions critical to ensuring supply security from that time. The GSOO has touted solutions such as LNG regasification terminals, new production sites, fast-tracking proposed projects, and developing new gas fields and transportation options. However, these solutions are costly, time-consuming, and unlikely to be operational in time to meet the imminent demand.

Don’t be under any illusion, Australia is not lacking in gas supply. As a replacement fuel for coal, there should be ample capacity to meet both domestic and power generation needs. However, up to 80% of the gas extracted in Australia is exported.
The government has tried to address this through the Gas Code of Conduct, which came into effect in 2023 and has, in some aspects, been successful. APLNG has agreed to supply 10PJ / year for four years at the gas cap of $12/GJ (CPI indexed) until 2029, an extension of the existing domestic supply deal, which was due to expire at the end of this year.

However, without clear investment signals and a significant gap between achievable contracts in the international and domestic markets, the market will inevitably follow the money. Gas will be required, regardless of advancements in batteries and renewables, gas-powered generation will still play a critical role. The government knows this, but with an election looming and energy policy at the centre of the debate, no one wants to acknowledge the elephant in the room or the cost of ignoring it.

Frequency Performance Payments starting in June

The wait is almost over for the implementation of the new Frequency Performance Payments.

In 2022, the Australian Energy Market Commission (AEMC) published a final determination and rule to change the way Primary Frequency Response (PFR) payments and regulation Frequency Control Ancillary Services (FCAS) payments are made. The rule change went into sandbox mode (non-financial industry trials) at the end of 2024 but will commence industry-wide on June 8, 2025.

As the National Electricity Market (NEM) evolves and quicker frequency response is required, maintaining grid security and keeping the power system frequency within the tight band around 50Hz becomes increasingly imperative. While electricity prices can be “controlled” by generators through bids into the dispatch mechanism, the ancillary services market has pass-through charges, which are levied onto end users to cover costs for inefficiencies in the system.

The new rule will introduce a double-sided frequency performance payment process, which will calculate, on a 5-minute basis, a generator’s ‘Contribution Factor’ to show the extent to which the unit has helped or is detrimental to the system frequency. As an end user, your previous calculation of FCAS, based on the ‘causer pays’ allocation, will also be replaced. The pass-through costs of FCAS will now also be calculated in 5-minute intervals, which will be based on the contribution factors. Those who have a helpful impact on frequency will receive payments, but those who are unhelpful will pay the penalty.

Those who react quickly to the market (batteries and hydro plants) will likely be the largest winners from this new mechanism. However, this will be funded by end users and renewable generators (solar and wind), who cannot react to the conditions. As such, this shake-up will likely have wide-reaching impacts upon financial inception.

LNP CQ-H2 DE-FUNDING

The future of the Central Queensland Hydrogen Project CQ-H2 is now uncertain after the new Queensland LNP government pulled any further funding for the project. The previously agreed $1.4b in funding, agreed under the Queensland Labor government, has been rejected by the new state energy and treasurer minister.

The project was part of Stanwell’s green hydrogen strategy, and the removal of funding has now put the project in doubt. The consortium of Australian (Incitec Pivot and Stanwell), Singaporean (Keppel) and Japanese (Iwatani and Marubeni) energy companies was to develop 720MW electrolysers, eventually scaling up to 2.8GW of electrolyser capacity. The government’s view was that the $1.4b of funding was vastly underestimated when reviewing the upgrades required to the water, ports, transmission and hydrogen production, and this would not align with the underlying requirement to produce affordable, reliable and sustainable power for the state.

The Acciona Energia Aldga solar farm (420MW), which is already at the Front Energy Engineering Design (FEED) stage and construction began last April, is also now under threat as the Stanwell Financial Investment Decision (FID) for the initial phase has not yet been made.

This is just the latest blow to the green hydrogen economy, following Fortescue’s withdrawal from the green hydrogen project in the Hunter, and Origin’s withdrawal from the Newcastle, Hunter Valley Hydrogen Hub.

All this de-investment seems in contrast to the federal government’s plans, which, via the “Future Made in Australia” plans, are still forging ahead with incentives, including tax credits from 2027 set at $2/kg of green hydrogen for up to 10 years.

The winners of this tax windfall could be those left standing. Projects such as the Yuri project in the Pilbara region of WA, a 10MW electrolyser powered via solar and batteries run by Engie (French) and Mitsui (Japanese) backing, is already under construction, although delayed by a year to be completed in 2025.

Overall, the landscape for large-scale hydrogen production in Australia has never looked so uncertain. With Canberra’s delay in announcing projects that would receive funding under the Hydrogen Headstart initiative still outstanding, the future continues to remove Australia from the appetite of international investors. This is now only exacerbated by the LNP’s removal of funding in Queensland, a possible indicator of what could occur if we do get a change in government in the next election.

Project Energy Connect Update

TransGrid have issued their update on Project Energy Connect (PEC), which showed the cost of the transmission line has almost doubled to $4.1b, which is twice that approved by the AER for the line, which was initially valued at $1.82b ($2.1b real).

With delays pushing the project’s full commissioning to late 2027—and that date still uncertain, the impact could be passed on to transmission-connected tariffs, potentially doubling them. The delays have been laid at the floor of COVID-19, labour shortages, the war in the Ukraine, floods and inflation. However, arguments are being heard that some of these should have been fully covered by contingency valuations.

In contrast the SA Electranet project has come in relatively on time and budget, again leaving questions as to why the TransGrid numbers are so much higher.

However, in good news for TransGrid, Elecnor, who in 2024 had indicated they would not be proceeding with Phase 2 of the project look to remain. They are cited as being under a fixed price arrangement of $3.6b, however they still have the option to walk away through the second stage if the project becomes unprofitable.

Overall, the re-negotiation with Elecnor will at least allow the second phase of the project to be started, a 700km line between Buronga and Wagga Wagga. However, they did not go as far as to ensure the AER additional funding would be approved or that the Elecnor issues that plagued stage 1 have been fully resolved. Overall, this is not a win for the project, the ongoing issues will lead to increased pass-through costs and likely further delays.

NEM Reform Consultation

The Department of Climate Change, Energy, Environment and Water (DCCEEW) is supporting the independent expert panel headed by Prof. Tim Nelson. The panel is preparing a roadmap and making actionable recommendations to support reforms to the NEM Wholesale Market.

The first consultation with stakeholders closed on February 14, 2025. This will be followed by a draft report in Q325, with the final report to be submitted to the Energy and Climate Change Ministerial Council in December 2025.

Investment incentives will likely focus on the several areas being looked to for comment.

The first being, can government certificated schemes promote investment in firmed, renewable generation and storage? This will favour those sites that can, via a combination of assets, likely solar, wind and battery, benefit from providing a firm, flat shape to the grid in addition to those currently in place via the CIS and LGC schemes. This will likely be welcomed by renewable developers and those retailers who have the ability to firm renewables around their existing large-scale assets. However, it will not be favoured by smaller single-site developers who will argue it will not allow competition but favour the larger participants of such a scheme. However, this could gain traction similarly to how the LGC scheme facilitated the development of 33,000,000 MWh of new renewable generation by guaranteeing a minimum certificate requirement for off-takers. Such a mechanism could potentially replace the LGC scheme post-2030, allowing for continued renewable development without requiring direct government support through programs like CIS.

The second area of focus will be the previously mentioned ESB Post-25 Capacity Mechanism scheme. Although not explicitly mentioned, it is the inference from the document’s questions. This was a controversial proposal by the ESB, as it would benefit only existing large-scale non-renewable generators at its core and could slow renewable investments. Although under a different guise, this has already occurred through the payments Origin will receive for the Eraring extension. This approach will likely continue throughout the 2020s and into the 2030s until sufficient storage and transmission infrastructure are in place to enable renewables to effectively meet the power demands of the NEM.

The wholesale market and consumer interaction will focus largely on the availability of Demand-Side Response (DSR). It may be preferable if these services can be included within the wholesale market. However, in reality, the NEM_DE (AEMO’s dispatch engine) cannot facilitate this. As such, the reforms may suggest these changes, but the likelihood of them being implemented is low.

The paper will likely result in more progressive tariffs and contracting, time-of-use reforms, and the ability to interact as an aggregated load (likely batteries) or feed-in tariffs at a time-of-use scale for consumers.

At the extreme, a full market overhaul should be proposed and will likely be presented by proponents. It is well-known that Australia operates under a pool mechanism, following previous pool models that have experienced soaring wholesale electricity prices and allowed participants to manipulate bid stacks. The likely replacement would be to move to a self-dispatch energy-only market, which would remove the requirements for capacity payments and a central dispatch model whilst encouraging competition. A reformed approach would have an underlying principle of bilateral trading where all output from generators must be contracted, removing the incentive to manipulate the prices in the pool spot market. This would bring the futures “Swap” market into a physical market, or a Futures market, which could run in parallel, as well as a “spot market”, which would run from the day ahead until just before delivery. Any imbalances not traded in these markets would be subject to imbalanced settlement pricing which could be significantly higher due to the calculations which underpin the cost of the balancing. All market participants would likely welcome this, bar those who are currently able to benefit from aggressive bidding behaviour and create a real time operating system.

This would significantly reduce AEMO’s role in the market and open up the ability for smaller generators, large off-takers and Distributed Network Operators to have access to the market and control the pricing and balance their assets in a much more controlled manner. It is likely any reforms suggesting this would receive significant lobbying and pushback within the government. PPAs and CFDs can still function within this market; however, they would be settled externally as financial products. The market, in turn, would provide better investment signals for operators and developers.

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?