Executive Summary

The National Electricity Market (NEM) is at a critical juncture. Current market settings are failing to send the investment signals needed to replace coal generation with reliable, dispatchable capacity. The Australian Pipelines and Gas Association submission, supported by Marsden Jacobs Associates analysis, confirms that under today’s energy-only market, private investors cannot justify building the 8.5GW of gas-powered generation (GPG) required by 2030, nor the 14.8GW needed to support a largely renewable system by 2025.

The implications of inaction are clear:

• Coal generation will stay online longer, increasing emissions and curtailing renewables.
• Reliability margins will tighten, exposing the NEM to higher unserved energy risk.
• Price volatility will escalate, driving up costs for consumers and industry.
• Critical gas supply, storage and pipeline infrastructure will be unprepared for the 2,750TJ/day winter peaks expected in the late 2030s.
• Emergency interventions will proliferate, leading to disorderly, expensive and carbon-intensive outcomes.

This submission supports the NEM Review’s preliminary view that gas-powered generation is uniquely placed to meet these challenges. It is fast-start, dispatchable and capable of running for days at a time – precisely what is needed to manage renewable droughts, extreme weather and coincident generator outages. It is not a competitor to renewable energy, but their enabler, allowing coal to exit sooner, increasing renewable utilisation and providing insurance against extreme price events.

The NEM Review’s Draft Report correctly identifies the need to value firm capacity explicit, co-optimise essential system services and deliver nationally consistent reform. APGA supports this direction and recommends the following targeted measures to close the investment gap, coordinate infrastructure development and provide certainty for investors.

Recommendation One: Establish an Electricity Service Entry Mechanism (ESEM)

APGA strongly supports the establishment of an enduring ESEM within the NEL to provide a stable, market-linked investment signal for bulk energy, shaping and firming.

• Inclusion of GPG and hydrogen turbines: It is critical that gas-powered generation and hydrogen turbines are explicitly included as eligible firming technologies. APGA agrees with the current definitions of firming and examples of technologies, which does explicitly include – or rather, not exclude, gas and hydrogen turbines.
• Contract design for low-capacity assets: APGA agrees that targeting contract support at the later years of a project’s life will help de-risk investment, particularly for low-capacity factor assets like GPG that need long-term revenue certainty.
• Industry co-design: APGA strongly recommends that industry be closely engaged in designing the contract frameworks so they are financeable, investable, and compatible with market operation.

Recommendation Two: Enable co-procurement of Essential System Services (ESS)

Projects supported by the ESEM should, where cost-effective, also be able to provide essential system services to maximise system efficiency and project viability.

• Efficient co-procurement: APGA agrees that permitting the combining firming contracts with ESS delivery is efficient and will likely improve project economics.
• Retrofit opportunities: The framework must explicitly allow assets to be retrofitted to deliver ESS, such as adding clutches or flywheels to existing gas turbines, consistent with the approach contemplated for Townsville Power Station in the Draft Report.

Recommendation Three: Establish a long-term Out-of-Market Reserve

Introduce a mechanism to procure medium- and long-duration capacity as “insurance” against rare but severe events like dunkelflaute periods or coincident outages.

Differentiate between 8–12 hour and multi-day firming streams, set emissions intensity thresholds aligned with net zero, and guarantee contracted availability during critical events. Payments must be sufficient to cover foregone market revenue and discourage withholding.

Recommendation Four: Provide policy certainty on emissions treatment

Clarify how emissions from firming projects will be treated under the Safeguard Mechanism and other climate policies.

Consider exemptions or reduced liability for ESEM-contracted capacity, or implement phased emission-intensity thresholds with offsets where exceeded. Align with the Australian Sustainable Finance Taxonomy (ASFT) so firm projects are recognised as enabling investments, while pairing with policies to scale renewable gas production and infrastructure blending so gas-powered generation has a pathway to net zero emissions.

The recommendations are summarised here for simplicity and are explored in further detail in the Recommendations section of this submission. Together, they will:

• Bring forward investable GPG capacity ahead of coal retirements.
• Coordinate gas supply, storage and transport infrastructure to meet peak-day deliverability.
• Contain price volatility and reduce reliance on costly last-minute interventions.
• Enable a faster, cheaper, lower-emissions transition for consumers.

1       Introduction

The Australian Pipelines and Gas Association (APGA) represents the owners, operators, designers, constructors and service providers of Australia’s pipeline infrastructure. APGA members ensure safe and reliable delivery of over 1,500 PJpa of gas consumed in Australia alongside over 4,500 PJpa of gas for export.

APGA commends the independent panel for its thoughtful and comprehensive approach to the NEM Review, particularly its recognition that current market frameworks are no longer sufficient to attract the investment required to meet Australia’s future energy needs.

This challenge is not new, but it is becoming urgent as we approach 2030 and beyond.

This is the fourth major examination of the National Electricity Market in the past decade. While each review has recommended a different pathway, they have consistently identified the same underlying issue: a market designed for a coal-dominated system is no longer fit for purpose in a grid dominated by variable renewables. Such a grid requires significant investment not only in renewable energy generation, but increasingly other services to provide system security and stability.

As set out through the NEM Review Draft Report, there are many options to adjust market settings to encourage investment in those services. APGA’s focus is on the significant new requirements for in gas powered generation (GPG) to provide firming services, similarly acknowledged by AEMO:[1]

GPG provides a reliable, firm and dispatchable supply of electricity that complements intermittent generation sources such as wind and solar generators. It can generate energy during periods of reduced production from renewable generators or when storage facilities have depleted their reserves, and can provide critical system security services to stabilise the grid.

Under the current energy-only market settings, returns are too uncertain to attract the necessary capital to invest. It is this key issue that APGA considers our priority to address in a future NEM, and one that AEMO has consistently highlighted in its advice to governments[2]:

While the scale of gas consumption remains uncertain through the energy transition, particularly gas usage for electricity generation, all scenarios identify the need for new supply investments to maintain supply adequacy.

APGA’s submission, supported by Marsden Jacobs Associates’ analysis, builds on the foundational work of the NEM Review by exploring three fundamental questions:

• Does the NEM require gas-fired generation to meet reliability standards in a renewable-dominated system?
• Will the current market design incentivise the level of gas-powered generation required?
• If not, what market, commercial, and infrastructure barriers must be addressed to deliver the required capacity, and how does GPG compare to other firming options?

The ISP forecasts that 14.8 GW of flexible gas-powered generation will be needed by 2050, nearly double the 8.55 GW required by 2030. APGA’s submission, supported by independent modelling, demonstrates that under current market settings this capacity will not be built.

Demonstrating its value
Since our last submission in February,[3] the role of gas-powered generation has been reinforced. In June 2025, gas-powered generation kept the Victorian system operating for several weeks following an unplanned outage at Yallourn Unit 3. In the days that followed, Mortlake Power Station recorded its second, third, seventh and ninth highest daily gas generation outputs since records began, while Laverton Power Station also set its highest ever single-day output. Across the month, Victoria used 4,363 TJs of gas for power generation — almost equal to 4,385 TJ total for the entire year of 2023.

An ongoing reliability challenge
Nexa Advisory[4] found at least one Yallourn unit was offline unexpectedly for 32 per cent of the year. As coal units age, outages will become more frequent and prolonged, forcing AEMO to lean even more heavily on GPG and imports to maintain system stability.

Investment viability
GPG has high capital costs but runs infrequently, meaning its business case depends on capturing revenues in a handful of high-price events each year. Without a mechanism that provides greater revenue certainty, new capacity will not be built — leaving the NEM exposed to price volatility, reliability events and potential load shedding as coal exits.

2       Background

The NEM Review Expert Panel has correctly identified that the current market frameworks are no longer sufficient to deliver the level of dispatchable capacity required for a secure, reliable and affordable transition. APGA strongly supports the Review’s focus on:

• Strengthening long-term investment signals to attract capital for new dispatchable capacity.
• Explicitly co-optimising essential system services (ESS) such as inertia, system strength, and operating reserves.
• Ensuring that new market mechanisms are technology-neutral, nationally consistent, and deliver consumer benefit.

These directions are critical but there is still significant work to do to ensure that gas-powered generation (GPG), as the only proven multi-day firming technology available at scale, is positioned to play its full role.

The post-2027 NEM must value firm capacity

The Federal Government’s Future Gas Strategy acknowledges the significant contribution that GPG will make over the coming decades and that there must be a continuous investment pipeline:[5]

“We cannot rely on past investments in gas to get us through the next decades. We need continued investment in, and development of, gas supply and transport infrastructure to get us through the energy transition with thriving industries.”

The Hon Madeleine King MP, Minister for Resources

The 2024 Integrated System Plan (ISP) projects that the NEM will require 75 GW of firm dispatchable capacity by 2050, in addition to large volumes of renewable generation and storage capacity. The Capacity Investment Scheme (CIS) is a valuable step toward meeting this need, now targeting 40 GW of capacity by 2030. However, only 9 GW of that capacity will be dispatchable, and thermal generation, including GPG, is explicitly excluded from the scheme.

This exclusion leaves a material gap in post-2027 investment signals. APGA agrees with the Panel’s Draft Report that the next phase of NEM reform must provide clear, bankable revenue streams for dispatchable capacity beyond 2027, particularly for technologies that can respond to prolonged reliability events. Without such a mechanism, the market will continue to under-deliver the capacity needed, forcing governments and market operators into expensive, short-notice interventions.

Gas remains critical for reliability

AEMO’s ISP projects that GPG will play a fluctuating but critical role as the backstop of the power system, with its output climbing sharply in the early 2040s as coal exits. On several winter days from 2039–40, gas demand for power generation is forecast to approach 2,500 TJ/day, requiring robust gas supply, storage, and transmission capacity. By 2050, 14.8 GW of GPG is forecast to be needed — almost double the 8.55 GW required in 2030.

Figure 1: Forecast capacity the NEM (GW, 2009-10 to 2049-50, Step Change) Source: AEMO, 2024, Integrated System Plan

Victoria’s experience in June 2025 underlines this point. As detailed in the Introduction, an entire year’s worth of gas for power consumption in one single month due to an outage.

This is a glimpse of the future NEM: a system where GPG is dispatched rarely but intensively, providing the last line of defence for reliability. The Panel is right to focus on investment signals for firm capacity, and APGA acknowledges the explicit inclusion of GPG as a firming technology to be supported under future market settings.

Managing emissions while maintaining reliability

APGA agrees with the Draft Report’s observation that firming technologies will make a relatively small contribution to Australia’s total emissions. GPG is expected to run at a capacity factor below 13 per cent, meaning its total emissions footprint will be modest. Nonetheless, emissions policy certainty is essential for investors.

The emissions profile of GPG can also be reduced over time. Biomethane is currently being produced in NSW, and is a mature technology overseas. As a carbon-neutral drop-in fuel that requires no turbine modifications, it can be immediately used to decarbonise gas fuel for GPG.

Most new gas turbines are already hydrogen-capable[6], and in Australia hydrogen blend-capable turbines are already being deployed, such as Tallawarra B and Hunter Power Project. Some international OEMs, such as Siemens Energy and Kawasaki, are now offering turbines capable of 100 per cent hydrogen combustion.

Hydrogen turbines can be supported through underground hydrogen storage in depleted gas reservoirs[7], especially when built adjacent to existing infrastructure such as Otway-Mortlake in Victoria and Roma-Kogan in Southern Queensland.

Clear guidance from governments on how emissions from firming projects will be treated under the Safeguard Mechanism, coupled with policies to scale up renewable gas and hydrogen production, will ensure GPG investment is compatible with net zero targets.

Reforming investment frameworks

While the ISP sends a strong signal that GPG is needed, as noted, the investment case remains extremely challenging. GPG plants may run only a few times per year, meaning their fixed costs must be recovered in a small number of high-price events. This creates volatile and uncertain revenue streams that do not support project finance.

The draft Review identifies this “tenor gap”, the mismatch between short-term contracting horizons and the long payback periods of capital-intensive assets. APGA supports the Panel’s recommendation for an Electricity Services Entry Mechanism (ESEM) with contract lengths that match asset financing requirements (10-15 years), giving investors the confidence to commit to new builds. Marsden Jacob Associates’ analysis, commissioned by APGA, provides a clearer picture about the factors underneath the aforementioned tenor gap as it pertains to GPG.

It is equally important to ensure that existing GPG capacity is retained until new capacity is online. The ISP does not currently model incentives to keep existing plants in service. Without intervention, early retirements could erode the reliability buffer just as coal exits accelerate, compounding the investment challenge.

Valuing more than just energy

APGA agrees with the Panel’s call to co-optimise procurement of essential system services (ESS) alongside energy and capacity. The NEM still does not explicitly price several critical services — including fast frequency response, operating reserves, inertia, and system strength — despite their growing importance as synchronous generation retires.

Frontier Economics described this challenge in 2021:[8]

Because there has historically been a reliable supply of these security-related services … the costs associated with maintaining the system in a secure operating state have not been reported and rewarded in the same way as other services in the NEM.

Valuing these services through co-optimised spot or contract markets will improve investment signals, reduce system security interventions, and strengthen project economics for firming assets such as GPG.

Recognising technology strengths and limits

Not all dispatchable technologies are equal. Batteries and pumped hydro have important roles, but each has limitations:

• Grid-scale batteries are well-suited for short-duration events and frequency regulation but cannot cover multi-day events without massive overbuild.
• Pumped hydro provides longer duration but faces high capital costs, geographical constraints, and climate vulnerability.
• GPG, by contrast, can effectively indefinitely provided fuel is available, making it uniquely capable of responding to renewable droughts and coincident coal outages.

Any mechanism to procure firming capacity must recognise these differences and value availability and duration, not just nameplate capacity.

A whole-of-NEM Approach

APGA welcomes the work of jurisdictions such as South Australia in progressing the Firm Energy Reliability Mechanism, but stresses that a nationally consistent, technology-neutral approach is essential. Fragmented state schemes risk duplication, inefficiency and investment uncertainty. A single NEM-wide capacity mechanism, with differentiated support for medium- and long-duration capacity, will provide the clarity and scale investors need.

This context sets the stage for the quantitative findings in Section 3, where Marsden Jacob Associates’ modelling demonstrates the commercial gap preventing new GPG investment and quantifies the reliability risk under current market settings.

3       GPG for an efficient NEM

In support of the NEM Review, APGA commissioned Marsden Jacob Associates (MJA) to conduct an in-depth analysis of GPG in the NEM. This work was initiated to fill key knowledge gaps about the reliability role of GPG through the energy transition.

The report, GPG for an efficient NEM, is due to be publicly released following this submission.

The aim of the study was to examine the role of GPG in maintaining system reliability as the generation mix transforms, particularly focusing on the period of accelerating coal plant retirements and growing renewable penetration. By quantifying GPG’s contributions and modelling future scenarios, the report provides evidence to inform the NEM Review’s considerations on how to ensure reliability in a net-zero emissions trajectory. 

The MJA analysis encompasses both a historical review and forward-looking modelling. It evaluates how GPG has performed as a “backstop” during recent supply stress events, and projects the future need for GPG capacity under a high-renewables future.

The study explicitly addresses what level of GPG investment the current market is likely to deliver versus what is required for reliability over the next 25–30 years. Crucially, it identifies potential shortfalls in GPG under status quo market settings and assesses implications for reliability, system costs, and emissions. It also assesses diesel generation as a potential contributor to the firming fleet, relative to or in combination with GPG.

This work supports the NEM Review by highlighting GPG’s role in an efficient transition and framing the interventions that may be needed to secure reliable capacity as the grid evolves.

Key Findings

Historical role of GPG in reliability

MJA’s review of 2022-25 events demonstrates that GPG has been vital in maintaining supply during unplanned coal outages and renewable shortfalls. Gas generators have repeatedly responded to cover sudden generation gaps, preventing load shedding and containing price spikes.

In one example, a wind lull coincided with temperatures over 37 degrees in high population centres in Queensland and New South Wales during 22 January 2025. Fast-start gas plants began immediately to meet high demand. Without that response, spot prices in New South Wales would have been an estimated $1,500–$2,400/MWh higher, and in Queensland $1,900–$3,800/MWh higher, sustained for hours.

This analysis highlights that GPG provides critical insurance against supply shocks, keeps the lights on, and caps extreme prices when coal units trip or when wind and solar output collapses in “dunkelflaute” conditions.

Table 1: Summary of historical review of GPG role during coal outage and wind lull events. Source: MJA analysis

Forward-looking modelling (AEMO Step Change Scenario)

MJA developed a NEM outlook aligned with AEMO’s 2024 Integrated System Plan Step Change scenario, updated with the latest data and policy announcements. This scenario assumes an ambitious but realistic transition: coal plants retire on announced schedules (with some life extensions tested), renewable generation and storage grow rapidly, and demand trends reflect the 2024 ESOO forecasts.

Table two: Key assumptions, MJA analysis

Notably, AEMO’s updated 2025 ESOO projects significantly higher demand than the 2024 ESOO used in this report, though still below the 2024 ISP Step Change scenario. Together with MJA’s base case, which assumes slightly lower demand and some coal staying online for longer, the modelling remains deliberately conservative. Even under these cautious assumptions, the analysis still shows a substantial build-out of gas-powered generation is required to maintain reliability through to 2040.

Figure 2: AEMO 2024 demand outlook compared with forecast 2025 ESOO demand. Source: AEMO and MJA

Under these assumptions, the modelling finds that significant new GPG capacity will be required to firm the system, especially in the 2030s as most coal capacity exits. GPG’s energy output remains relatively low (operating at low-capacity factors in normal conditions) but its firm capacity becomes increasingly essential to meet peak demand and prolonged low-renewable periods.

Figure 3: Closures of coal-fired generators. Source: MJA

 Shortfalls in GPG investment under current market settings

MJA’s modelling shows a clear gap between the level of GPG the system will require to maintain reliability and the level that the market would deliver under current energy only conditions. Even in the Step Change outlook, with higher price volatility and coal retirements driving greater need for firming, the modelled investment pipeline remains insufficient.

Crucially, the economic case for new peakers does not stack up. As demonstrated in Figure 4 below, internal rates of return (IRRs) for most new units sit well below the benchmark hurdle rate for investment. The colours signify if economic (green – IRR achieved) and if not economic (yellow – IRR not achieved). In other words, under today’s market design, the private sector cannot justify building the capacity the system needs.

Figure 4: IRRs achieved for the GPG developed, categorised by type of investment party. Source: MJA

Vertically Integrated Retailers

Independent Power Producers

This gap is partly obscured in the modelling by the assumption that the NEM Reliability Standard must always be met. In reality, if new capacity is not commercially viable, it may simply not be built, leaving the system to rely on last-minute interventions or extended coal generation to keep the lights on.

Further analysis of the commercial and financing barriers driving this shortfall is provided in the Commercial challenges for GPG section on Page 17.

Regional and timing differences in GPG needs

MJA’s modelling confirms that GPG requirements emerge in distinct waves across the NEM, closely following the coal retirement schedule, regional demand growth, and renewable build-out. The analysis underscores that investment timing matters, and delays in any region risk forcing coal life extensions or triggering unserved energy events.

NSW and Victoria

Both NSW and Victoria are at the frontline of reliability risk. They face the earliest and steepest uplift in GPG requirements, reflecting their imminent coal exits and limited firming capacity.

In NSW, post-2025, the firm capacity margin sits below POE10 demand more frequently, with GPG gas usage more than doubling from ~20 PJ/year in the late 2020s to >50 PJ/year by the late 2030s. Peak daily gas demand exceeds 1,000 TJ/day through the 2040s, meaning even small delays in new capacity would expose NSW to reliability events.

Figure 5: NSW forecast GPG demand (Regional Annual Gas Use and Maximum MDQ), MJA NEM Base Case. Source: MJA

In Victoria, Yallourn’s 2028 retirement creates a similar step-change, with gas usage climbing from under 10 PJ/year in the 2020s to nearly 30 PJ/year post-2035. Peak daily approaches 750 TJ/day from 2040.

Figure 6: Victoria forecast GPG demand (Regional Annual Gas Use and Maximum MDQ), MJA NEM Base Case. Source: MJA

NSW and Victoria must move first where gas-powered generation plants must reach financial investment decision within the next 18-24 months to ensure new units are operational before coal exits. Failure to commit early will force costly market interventions or seasonal coal operation beyond 2030, undermining decarbonisation goals and raising system costs.

Queensland

Queensland will experience delayed but must stronger growth than other states. As Queensland’s coal fleet retires closer to 2035-40, its need for large-scale GPG capacity is similarly delayed – notwithstanding the imperative to reduce carbon emissions. However, once the retirements begin, the ramp-up in gas demand is much steeper than in any other region.

• Annual GPG gas consumption surges from ~20 PJ/year in the early 2030s to almost 70 PJ/year by 2045 — a more than three-fold increase in just over a decade.
• Peak daily gas demand more than doubles, moving from around 400 TJ/day to over 800 TJ/day.

Figure 7: Queensland forecast GPG demand (Regional Annual Gas Use and Maximum MDQ), MJA NEM Base Case. Source: MJA

This has two strategic implications. First, that infrastructure lead times matter. Pipeline capacity and upstream supply must be planned now to meet these MDQ levels by the late 2030s. Leaving investment signals too late risks bottlenecks that could restrict dispatchable generation at precisely the point coal capacity exits.

Secondly, market design must enable earlier FID. Queensland GPG projects will only proceed if revenue certainty is provided in advance — such as through capacity mechanisms or firming contracts that recognise the need to build before the reliability gap materialises.

South Australia

South Australia is already coal-free and has among the highest renewable penetrations in the world, but the modelling shows its reliance on gas remains non-negotiable for firming.

The state’s OCGT fleet continues to play a critical role in covering net-demand peaks and contingency events, particularly during wind droughts. Even with strong interconnector development, South Australia retains a requirement for fast-start GPG to maintain system security, with capacity factors likely to stay low but strategically important.

This means policy should focus on preserving or modernising South Australia’s fast-start fleet, potentially through flexible service markets that reward quick response rather than pure energy output. Decommissioning these units without ensuring their replacement would expose the region to supply security risks and force higher reliance on imports during tight conditions.

System-wide winter peak challenge

Across the NEM, the modelling shows winter peak demand becoming the binding reliability constraint once coal exits accelerate in the late 2030s. Maximum daily gas demand peaks at ~2,750 TJ/day — a level that will require every part of the east coast gas system (pipelines, storage, import terminals) to operate in concert and without a single point of failure.

Figure 8: Forecast annual gas demand and MDQ for the southern gas market. Source: MJA

Commercial challenges for GPG

The analysis highlights a structural “missing money” problem for new GPG under the current energy-only market design. The challenge is not technical, the modelling shows the NEM will require significant new GPG capacity, but commercial, as the revenue streams available to investors are insufficient to justify development.

IRR findings – failing the investment test

The modelling calculates internal rates of return (IRRs) for new GPG projects and compares them against the 9% pre-tax real hurdle rate specified by AEMO for new OCGT investments. The results are sobering:

• Most new-build GPG fails to achieve the 9% IRR under expected market conditions, even in the Step Change outlook with elevated price volatility.
• Vertically integrated (VI) retailers achieve the lowest IRRs, because they optimise their portfolio around existing coal and renewables, dispatching GPG only as a last resort to minimise overall portfolio cost. The result is fewer running hours, lower energy revenues, and under-recovery of fixed costs.
• Independent power producers (IPPs) achieve slightly higher IRRs because they run more opportunistically, but the increased merchant risk, with no guaranteed capacity payments, makes their projects very difficult to finance at commercially acceptable gearing levels.

MJA notes the 9% benchmark itself is likely too low in today’s risk environment. Policy risk, fuel price volatility, and exposure to extreme events mean investors would demand a higher return to commit equity, closer to 10–12%, further widening the investment gap:

The market currently does not send a sufficient signal to develop the firming capacity that the system will require. This is a textbook example of a reliability externality — the benefits of GPG (avoiding load shedding, containing price spikes) are largely socialised, while the cost of building and holding capacity sits entirely with the investor.

Business model constraints

MJA’s analysis distinguishes between the two main types of proponents.

Vertically-integrated retailers or ‘gentailers’ typically build GPG as a physical hedge against their large retail book. They value GPG as “insurance” more than as an energy producer, and when they already own other dispatchable assets (especially coal), they minimise GPG run-time. This makes new GPG economically unattractive unless their legacy coal fleet retires or unless capacity mechanisms compensate them for simply being available.

Independent power producers (IPPs), meanwhile, operate fully merchant and depend on capturing volatility in the wholesale market. Their revenue is inherently uncertain and may be eroded by interventions such as price caps, Reliability and Emergency Reserve Trader (RERT) activation, or out-of-market directions. This uncertainty drives lenders to apply lower debt gearing and demand higher equity returns, pushing up the cost of capital.

Both models therefore struggle to produce bankable business cases for new GPG without some form of revenue certainty beyond the energy market.

Infrastructure requirements: gas supply, compression, and storage

MJA’s analysis makes clear that building new power stations alone is insufficient. For GPG to play its reliability role, the gas system that supplies those stations must be capable of delivering very large volumes of gas on rare but critical days. The East Coast Gas Market will require targeted development of supply, compression and storage infrastructure to ensure this peak deliverability is available when needed.

Peak delivery challenge

By the late 2030s, maximum daily gas demand for GPG approaches 2,750 TJ/day. These peaks coincide with winter demand, when residential and industrial loads are already elevated, placing additional stress on the system. Without investment in pipeline capacity and storage withdrawal rates, GPG output could be limited at precisely the times when it is most critical for maintaining power system security.

Key infrastructure needs

MJA identifies a series of requirements to meet this challenge:

• Pipeline reversals and compression upgrades: The full reversal of the Eastern Gas Pipeline is needed to enable flows of northern gas into Victoria, replenishing storages such as Golden Beach and Iona. Compression upgrades along key transmission routes, including the Moomba–Sydney Pipeline and SEA Gas Pipeline, may also be required to support high short-notice flows.
• Expansion of storage capacity: Storage projects such as Golden Beach must be delivered ahead of accelerating Gippsland decline. Expansion of Iona’s working capacity and deliverability is also essential to meet short-duration winter peaks.
• Development of new gas supply: Replacement of declining Gippsland production is required to ensure sufficient gas molecules are available to meet simultaneous residential, industrial and GPG demand. MJA points to projects such as Narrabri gas, Beetaloo production, and LNG import terminals (Port Kembla, potentially in Victoria) as options to fill the emerging supply gap.

Utilisation characteristics

MJA notes that these assets will be underutilised for most of the year, with high utilisation occurring only during peak winter events or during extended renewable shortfalls. This characteristic is consistent with a renewable-rich grid where dispatchable gas generation is called on infrequently but must be able to respond at scale. Ensuring that storage, compression and transport infrastructure can operate reliably during these few events each year is central to the effectiveness of GPG as a reliability tool.

Diesel is not a viable alternative 

The report also considered whether diesel-fired generation could substitute or supplement for GPG in providing firm peaking capacity. The findings indicate that diesel is an inferior and impractical option for the NEM’s needs. While diesel generators can be quick to deploy for emergency backup, they suffer from much higher fuel costs and significantly higher emissions.

Comparing both cost and performance, MJA’s analysis finds that relying on diesel for firming would result in prohibitively expensive energy during peak periods. This is partly due to the cost of diesel fuel, which is several times the cost of natural gas per GJ, and the logistical arrangements surrounding transport and storage. Operationally, diesel units are generally smaller and less efficient; scaling them up to the required capacity would be challenging and come with reliability concerns. The market interactions between diesel and GPG would also lead to volatility, where diesel would always act as a price setter. All of this leads to higher volatility, less efficiency, and higher cost.

In short, diesel is not a realistic long-term solution for a transitioning NEM – it cannot match gas generation in cost-effectiveness or scalability for large-scale peak support. This underscores the importance of investing in gas-powered generation, or other equivalent firming technologies, rather than hoping to fall back on diesel in a crisis.

Implications

MJA’s modelling has profound implications for reliability, investment planning, and transition costs across the NEM. The date makes clear that the current market trajectory will not deliver the scale or timing of GPG needed for an efficient coal-to-renewables transition.

1. Market design will under-deliver required capacity

MJA’s IRR modelling shows that most new GPG projects achieve IRRs well below the 9% pre-tax real hurdle rate, even in the Step Change outlook. This remains true across both vertically integrated gentailers and independent power producers.

• Energy market revenues cover only a fraction of required fixed costs, with units running at capacity factors too low to recover capital and operating expenses.
• The revenue gap persists even with elevated price volatility, showing that scarcity pricing alone is insufficient to fund the level of capacity required.
• Risk premiums push the bar even higher: MJA notes that investors are now seeking 10–12% real returns given fuel price volatility and carbon policy uncertainty, widening the gap further.

The outcome is a structural “missing money” problem: even if the system clearly needs peaking plant for reliability, investors will not commit capital without revenue certainty. The modelling highlights that this gap is not a marginal problem — it is a multi-GW shortfall that will grow materially as coal retirements accelerate.

2. Delayed GPG build forces coal extensions

MJA’s sensitivity analysis is unequivocal: without sufficient and timely GPG investment, the only way to meet the reliability standard will be by retaining equivalent amounts of coal capacity beyond announced closure dates.

• A shortfall of ~2,000 MW of planned GPG capacity results in an equivalent 2,000 MW of coal (for example Bayswater or Loy Yang A units) staying online.
• These coal units are not designed to operate in a system with high renewable penetration. This will force them to cycle more frequently, ramp rapidly, and run less efficiently — leading to higher maintenance costs and greater emissions intensity.
• This also suppresses the utilisation of renewables, resulting in higher curtailment and wasted low-cost generation.

In practical terms, failure to build GPG on time locks in coal life extensions years in advance, as these decisions require planning lead times for fuel, safety compliance, and workforce retention.

3. Reliability margins will tighten and price spikes will escalate

The modelling shows that reserve margins narrow materially from 2028 onward as Yallourn retires, with further tightening post-Eraring and again in the late 2030s as Queensland coal exits.

• Unserved energy risk rises steeply in scenarios where GPG build is delayed, breaching the reliability standard unless emergency capacity is procured.
• Price volatility will intensify: The report points to 2022–2025 historical events where spot prices would have spiked by $1,500–$3,800/MWh higher for hours at a time if GPG had not responded. These events will become more common as the system loses inertia and dispatchable coal capacity.
• Consumers bear the cost through higher wholesale prices, increased frequency of RERT activations, and potentially through involuntary load shedding if capacity is not available in time.

4. Fuel infrastructure is now a binding constraint

Even if GPG capacity is built, it cannot deliver unless gas molecules can be delivered at scale on peak days.

• Maximum daily demand for GPG reaches ~2,750 TJ/day by the late 2030s, stretching pipeline, compression and storage infrastructure.
• Without EGP reversal, Moomba compression upgrades, and storage expansions at Iona and Golden Beach, southern states risk winter supply gaps that could curtail GPG output.
• New gas supply sources such as Narrabri, Beetaloo and LNG import terminals must come online ahead of these peak demand periods to replace declining Gippsland Basin production.

This means fuel infrastructure must be developed on the same timeline as GPG capacity — a coordinated approach is essential to avoid stranded power stations or fuel shortages during critical periods.

5. Diesel is a non-solution

MJA’s cost analysis confirms that diesel cannot realistically fill the reliability gap.

• Diesel fuel costs are several times higher per GJ than natural gas, making prolonged dispatch prohibitively expensive.
• Diesel units are typically small, inefficient, and logistically constrained, requiring significant fuel storage and frequent maintenance to sustain high run-hours.
• Large-scale diesel reliance would materially increase emissions and breach the NEM’s net-zero trajectory.

Summary

The conclusion from MJA’s work is unambiguous: under current market settings, the NEM will not deliver enough GPG capacity to replace coal. The result will be a combination of:

• Higher costs from emergency procurement, out-of-market reliability interventions, and inefficient coal cycling.
• Delayed emissions reduction due to coal life extensions.
• Greater price volatility and reliability risk borne by consumers.

To avoid these outcomes, policy must ensure that GPG projects reach financial close well ahead of coal retirements and that gas infrastructure is fuel-secure by the late 2030s. Without such intervention, the transition will be disorderly, more expensive, and more carbon-intensive than necessary.

4       Response to specific recommendations

Based on the above findings, APGA strongly supports the NEM Review Panel to consider a set of measures to ensure reliability through the transition. Targeted intervention is needed to bridge the investment gap for GPG and other firming technologies. 

Recommendation 8A: Establish an Electricity Services Entry Mechanism (ESEM) in the NEL

APGA strongly supports the establishment of an enduring ESEM within the NEL to provide a stable, market-linked investment signal for bulk energy, shaping, and firming.

• Inclusion of GPG and hydrogen turbines: It is critical that gas-powered generation and hydrogen turbines are explicitly included as eligible firming technologies. APGA agrees with the current definitions of firming and examples of technologies, which does explicitly include – or rather, not exclude, gas and hydrogen turbines.
• Contract design for low-capacity assets: APGA agrees that targeting contract support at the later years of a project’s life will help de-risk investment, particularly for low-capacity factor assets like GPG that need long-term revenue certainty.
• Industry co-design: APGA strongly recommends that industry be closely engaged in designing the contract frameworks so they are financeable, investable, and compatible with market operation.

Recommendation 8B: Enable provision of Essential System Services

Projects supported by the ESEM should, where cost-effective, also be able to provide essential system services to maximise system efficiency and project viability.

• Efficient co-procurement: APGA agrees that permitting the combining firming contracts with ESS delivery is efficient and will likely improve project economics.
• Retrofit opportunities: The framework must explicitly allow existing assets to be retrofitted to deliver ESS, such as adding clutches or flywheels to existing gas turbines, consistent with the approach contemplated for Townsville Power Station in the Draft Report.

Recommendation 8D: Establish a long-term out-of-market reserve

A significant gap in current market settings is the absence of a mechanism to plan, price and invest for high-impact, low-likelihood events. These events, such as renewable droughts, coincident generator outages or extreme weather, are unpredictable, potentially catastrophic and, as climate variability increases, likely to become more frequent.

APGA supports the establishment of a long-term out-of-market reserve to address this risk. In our February submission, we proposed a capacity investment mechanism that differentiates between types of capacity, with targeted support for medium- and long-duration firming that are currently not incentivised under existing market arrangements.

The scheme should:

• Differentiate duration support: Include a medium-duration stream (8–12 hours at 80% nameplate capacity) and a long-duration stream (capable of maintaining 80% nameplate capacity for multiple days, long enough to outlast dunkelflaute events).
• Include emissions and transition safeguards: Require that any new investment supported after 2040 sits within a portfolio that is credibly transitioning to net zero, and apply an emissions-intensity limit to all procured capacity.
• Guarantee availability: Ensure that tendered participants can deliver when required, limiting the ability to participate in the daily market in ways that could compromise reliability. Payments must be sufficient to compensate for foregone market revenue and to discourage withholding behaviour.

This mechanism would provide the “insurance policy” the market currently lacks, ensuring that the NEM can withstand rare but severe events without resorting to ad hoc interventions or involuntary load shedding.

Recommendation 9A: Provide policy certainty on emissions treatment

APGA supports the recommendation that governments clarify how greenhouse gas emissions targets will apply to projects procured to provide firming services. Investors must have certainty on how emissions are treated over the life of projects that will be procured under mechanisms such as the ESEM.

Firming projects, by design, will have relatively low capacity factors and therefore relatively low overall emissions. As the draft report notes, gas-powered generation (GPG) is likely to operate below a 13 per cent capacity factor in the future, meaning its total emissions contribution to the NEM will be small. Nevertheless, investors need clarity on whether and how these emissions will be subject to obligations under the Safeguard Mechanism or future emissions reduction schemes.

Managing emissions obligations

APGA sees two main avenues to manage this issue and recommends that governments consider both:

• Exemptions or Reduced Liability: Projects procured under the ESEM could be granted partial or full exemptions from emissions reduction requirements. This would recognise their unique reliability role, especially when they are dispatched during periods of low renewable generation. However, any exemption must be carefully designed to avoid distorting competition. Competitive market-procured firming services must not be placed at a disadvantage compared with ESEM-procured capacity. A transparent and level playing field is essential to ensure the most efficient mix of investment.
• Emissions intensity thresholds and offsets: Governments could apply emissions intensity thresholds, phased in over time, aligned with Australia’s net zero trajectory and international best practice. This would create a clear pathway for investment in lower-carbon fuels, including biomethane, hydrogen blends, and carbon capture solutions.
  Where emissions exceed the threshold, requiring offsets would ensure that projects still meet overall climate objectives while preserving investor confidence.

Australian Sustainable Finance Taxonomy alignment

An additional policy consideration is the interaction with the forthcoming Australian Sustainable Finance Taxonomy. If firming projects are classified as “transition” or “green” activities only under strict emissions criteria, there is a risk that finance for GPG could be constrained just as it is most needed. APGA recommends that governments work with the Australian Sustainable Finance Institute to ensure that firming projects can be recognised as enabling activities within the transition taxonomy, provided they are credibly aligned with decarbonisation pathways and emissions thresholds.

Incentivising low-carbon fuels

Firming services must be supported by a parallel policy framework that accelerates the decarbonisation of the fuels they use. Many turbines procured under the ESEM will be dual-fuel capable, running on both gaseous and liquid fuels, and most new GPG turbines can also accommodate hydrogen blends. Policies should therefore:

• Encourage investment in low-carbon gases such as biomethane and renewable hydrogen.
• Support infrastructure upgrades to enable blending and eventual full substitution of natural gas.
• Provide clear demand signals for low-carbon fuels, including through dedicated targets or support programs, to make decarbonising GPG commercially viable.

By combining emissions clarity with a credible transition pathway for fuels, governments can provide investors with the confidence to commit capital to firming projects while ensuring that these investments remain compatible with net zero targets.

Conclusion

Gas-powered generation has a pivotal role in an efficient NEM transition. The MJA report findings reinforce that proactive policy and market reforms are needed to unlock this role. By implementing targeted investment signals, embracing a technology-neutral reliability framework, and planning for the requisite infrastructure, the NEM can secure the flexible, dispatchable capacity it needs to complement renewables.

These recommendations will help ensure that reliability is maintained at lowest cost to consumers, emissions goals are met, and the transition away from coal is managed smoothly with gas generation as a stabilising force rather than a last resort. The NEM Review is an opportunity to put these measures in place before reliability shortfalls materialise. APGA urges the Panel to take this evidence into account when making final recommendations on facilitating an efficient and reliable NEM for the future.

[1] AEMO, 2025, 2025 Gas Infrastructure Options Report, https://www.aemo.com.au/-/media/files/stakeholder_consultation/consultations/nem-consultations/2025/2025-gas-infrastructure-options-report/final/2025-gas-infrastructure-options-report.pdf

[2] AEMO, 2025, 2025 Gas Statement of Opportunities, https://www.aemo.com.au/-/media/files/gas/national_planning_and_forecasting/gsoo/2025/2025-gas-statement-of-opportunities.pdf

[3] APGA, 2024, Submission: NEM Wholesale Market Settings Review Consultation, https://apga.org.au/submissions/nem-wholesale-market-settings-review-initial-consultation

[4] Nexa Advisory, 2025, Coal performance in the National Electricity Market: Case Study 3 – Yallourn Power Station, https://nexaadvisory.com.au/web/wp-content/uploads/2025/05/Nexa_Coal-performance-in-the-NEM-case-study-3-Yallourn.pdf

[5] DISR, 2024, Future Gas Strategy, Minister’s forward, https://www.industry.gov.au/sites/default/files/2024-05/future-gas-strategy.pdf

[6] CSIRO, 2025, GenCost 2024-25 Final Report, https://www.csiro.au/-/media/Energy/GenCost/GenCost-2024-25-Final_20250728.pdf

[7] FFCRC, 2025, RP1.1-07 Final Report: Long-Duration Energy Storage: Techno-economics and provision of reliability and resilience to the NEM, https://www.futurefuelscrc.com/project/rp1-1-07-integrated-electricity-hydrogen-future-system-and-market-interactions-under-different-storage-considerations/

[8] Frontier Economics, 2021, The role of gas in the transition to net-zero power generation, https://apga.org.au/hubfs/frontier-economics-summary-stc.pdf