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?

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.