Managing the Transition to Renewable Energy

2025 renewable energy target 

The Act sets a target that 40 per cent of the electricity generated in Victoria will come from renewable sources by 2025. The department reported that Victoria achieved a renewable energy share of 39.1 per cent across the 2024 calendar year (see Figure 6).

Figure 6: Percentage of renewable energy out of the total energy generated from 2006 to 2024

Source: VAGO, based on department data.

The department’s reporting is based on publicly available NEM data from AEMO and statistics from the Australian Department of Climate Change, Energy, the Environment and Water for data AEMO has not reported. 

These are reputable sources and the data is high quality.

The department also subjects renewable energy target progress reports to external review. The latest external review validated the accuracy of the Victorian Renewable Energy Target 2023/24 Progress Report, which included renewable energy target values for 2013–14 through to 2023–24.

Using the same data and the department’s methodology, we were able to reproduce the department’s reported renewable share for 2020 and 2024. This gives reasonable assurance that the department’s renewable energy target progress reporting is reliable.

We extended our modelling to estimate whether Victoria is on track to achieve a 40 per cent renewable share across 2025 under different demand and electricity generation scenarios. 

Based on our analysis, there is a range of plausible scenarios for which Victoria’s renewable energy share for 2025 exceeds the renewable energy target (see Figure 7). 

Figure 7: Our renewable generation share modelling, under different scenarios, for 2025

Note: AEMO’s assumptions for wind and solar farms are more conservative than the department’s. The Golden Plains wind farm is the largest renewable energy project scheduled in Victoria for 2025. 

Source: VAGO, using data from AEMO and the department.

2030 renewable energy target

The pathway to meeting the 2030 renewable energy target is less certain than for 2025 and will rely on the CIS.

The Australian Government–Victoria Renewable Energy Transformation Agreement sets out capacity allocations under the CIS. Victoria has been allocated at least:

• 5 GW or 11 TWh of renewable generation capacity
• 1.7 GW or 6.8 GWh of 4-hour duration equivalent storage capacity.

In 2024, the department advised the government that Victoria was tracking towards a 58 per cent renewable energy share in 2030 following the closure of Yallourn in 2028. The department also advised that Victoria's full CIS allocation could increase Victoria's renewable energy share to 61 per cent. However, additional Victorian Government support will be necessary to reach 65 per cent.

In its advice, the department estimated that Victoria will require the completion of $1.2 billion in transmission upgrades by 2030 to reduce network curtailment and improve the economic viability of proposed CIS projects.

VicGrid is proposing to fast-track new transmission projects under the Victorian Transmission Plan, including the:

• Western Victoria reinforcement program, which will support the connection of onshore wind and solar generation across western Victoria
• Eastern Victoria reinforcement program, which will ensure the connection and security of supply in eastern Victoria, including the Gippsland offshore wind area. 

This is in addition to the already-committed Western Renewables Link and VNI West projects.  

Greater-than-expected growth in demand for electricity could be a significant risk to meeting the 2030 target. Increased electricity demand leads to an increased reliance on generation from existing assets, including coal and gas generation.

2030 energy storage target

Victoria has enough battery capacity planned to make it likely that it will meet its target to achieve 2.6 GW of energy storage by 2030.

AEMO data showed 1 GW of battery storage capacity in service before July 2025, with up to 4.7 GW in new capacity scheduled to come online by 2030. 

If completed on time, this means up to 5.8 GW of one-hour to 4-hour battery projects may be online by 2030 – more than double the 2.6 GW target.

Delays to offshore wind targets

Victoria will not meet its target for 2 GW of offshore wind energy by 2032. This is because of delays confirming a suitable port to support the construction of offshore wind farms and delays opening offshore wind auctions.

It will take until at least the end of 2033 for Victoria to build 2 GW of offshore wind capacity, but there is a risk of further delays due to port issues and funding uncertainty.

Offshore wind port options

The Victorian Government's original strategy was to develop an offshore wind port, known as the Victorian Renewable Energy Terminal, at the state-owned Port of Hastings. Construction was due to start in February 2026 and finish by December 2028.

In October 2023 the Port of Hastings Corporation, which manages the port, referred the proposed Victorian Renewable Energy Terminal to the Australian Minister for the Environment and Water. 

The Port of Hastings Corporation needed the Minister’s approval because of the terminal’s potential impact on nearby Ramsar-protected wetlands. In January 2024 the Minister rejected the referral due to unacceptable impacts on the wetlands.

The department and the Port of Hastings Corporation are now pursuing 2 port strategies simultaneously (see Figure 8). 

Figure 8: The Victorian Government’s offshore wind port strategies

Source: VAGO.

The Port of Hastings Corporation submitted a revised proposal for the Victorian Renewable Energy Terminal in June 2025.

The department has informed offshore wind developers that it will provide details of the government’s preferred port strategy before opening auctions, originally scheduled for quarter 3 of 2025. But the Australian Government is yet to decide if it will allow the revised Victorian Renewable Energy Terminal to proceed. The department has also not yet negotiated multi-port agreements. 

The government has delayed opening the auctions until at least 2026.

Further delays finalising a port solution and opening auctions will reduce the achievability of 2 GW by the end of 2033 (and 4 GW by 2035) given the department assumes a maximum feasible construction rate of 1 GW per year.

SEC battery storage projects

SEC is committed to investing in 4.5 GW of new renewable electricity generation and storage capacity by 2035, including 1 GW of storage by 2028. 

SEC is on track to deliver its 2028 storage target. It has committed to investments in 700 MW of electricity storage capacity across 2 projects, which it plans to deliver by 2027. 

It is also identifying and assessing new investment opportunities. As of March 2025, it was undertaking due diligence on opportunities with a total storage capacity of around 1 GW.

The Wooreen battery

In March 2021, the state entered into a structured transition agreement with EnergyAustralia to manage the scheduled Yallourn closure by 30 June 2028.

Under the agreement, EnergyAustralia committed to procure, construct and operate a 350 MW, 4 hour duration battery (known as the Wooreen battery). The Victorian Government and EnergyAustralia agreed that it would be operational by 31 December 2026 but later agreed to a revised date of 30 June 2027.

Construction has started; however, the Wooreen battery is not expected to be online until December 2027. This will still be before the scheduled closure of Yallourn.

VRET2 projects progress

The second Victorian Renewable Energy Target auction (VRET2) is off track. It will not contribute as expected to:

Victoria meeting its 2025 renewable energy target

• realising the Victorian Government's commitment to source 100 per cent renewable energy for all government operations by 2025. 
• The department also expected VRET2 battery projects to help offset the estimated firm energy gap after Yallourn’s closure. But this is at risk.

The department’s original plan was that VRET2 would support 6 privately developed renewable energy projects to start operating by the end of 2024. But Glenrowan Solar Farm was the only VRET2 project to start operations by the end of 2024.

Two other VRET2 projects now have target operating dates in 2027, including the SEC Renewable Energy Park – Horsham. The remaining 3 projects have no confirmed target operating dates (see Figure 9).

Figure 9: Status of VRET2 projects

Source: VAGO, based on information from the department.

Additional transmission infrastructure

Victoria requires significant expansion in renewable electricity generation and storage to meet its electricity needs as coal-fired power stations close. Extensions and upgrades to Victoria’s transmission network are necessary to enable this expansion.

The government’s plans to close Yallourn and Loy Yang A assumed the timely completion of key transmission projects to ensure a reliable electricity supply. 

AEMO, AusNet and Marinus Link Pty Ltd are managing these projects in consultation with the Victorian Government.

As well as existing projects, the Victorian Transmission Plan proposes around a $1.2 billion investment in new transmission capacity by 2030 to facilitate new projects under the CIS. 

Delays to transmission infrastructure

The department assumed the following completion dates for these transmission projects:

• Western Renewables Link by 2025, later revised to 2027
• VNI West by June 2028
• Marinus Link Stage One by 2031–32 and Stage Two by 2034–35.

But both the Western Renewables Link and VNI West face delays (see Figure 10).

Figure 10: Transmission project timelines

Source: VAGO, based on public construction timelines.

The Western Renewables Link timeline now expects construction to start in quarter one of 2027 and finish in quarter 4 of 2029. The project requires a planning scheme amendment before construction can start. The timeline expects the Minister for Planning to finalise this amendment in late 2026.

VNI West’s commissioning depends on the Western Renewables Link coming online first. As of July 2025, the expected completion date for VNI West is late 2030.

Marinus Link’s 3 shareholders – the Victorian, Tasmanian and Australian Governments – issued a final investment decision to proceed with Marinus Link Stage One in August 2025. Pending the timely completion of further financial and regulatory steps, construction should start in 2026.

Reliability standards

A reliable electricity system has enough generation, demand response and network capacity to meet consumer demand in all conditions. It is about ensuring there is enough generation capacity and that the transmission and distribution networks can reliably deliver electricity to customers when they need it. 

An electricity shortfall can lead to load shedding or blackouts.

There are 2 standards to understand the reliability of the NEM. Both are based on the amount of demand that the electricity network is forecast to be unable to meet. This is known as unserved energy.

AEMO’s reliability forecasts 

AEMO publishes annual forecasts for unserved energy in its annual ESOO. These forecasts inform the department’s advice on electricity reliability risks. The department is responsible for assessing risks and uncertainties associated with AEMO’s forecasts and assumptions and appropriately advising the government on the implications.

To produce its forecasts, AEMO simulates a wide range of future operating conditions based on different levels of demand, historic weather, power station outages and supply assumptions. AEMO uses these simulations to forecast unserved energy in future years using probability weighted annual averages, including under a committed and anticipated developments scenario.

In the committed and anticipated developments reliability assessment in the 2024 ESOO, AEMO forecast that Victoria would face electricity shortfalls against the interim reliability measure from 2027–28 and against the reliability standard from 2028–29, increasing after Yallourn closes.

But in the 2025 ESOO, AEMO forecasts that under the same assessment electricity shortfalls against the reliability standard will not occur until 2030–31 (see Figure 11).

Under the committed and anticipated developments assessment, AEMO forecasts that 1.7 GW of new generation capacity and 7 GWh of new battery projects will be delivered by mid-2028. It expects this to outweigh the negative effects of forecast higher electricity demand and delays to transmission projects.

These figures do not include new CIS-supported projects that have not yet met AEMO’s criteria.

While Victoria’s reliability outlook to 2030 has improved, the outlook is sensitive to key supply and operational risks. 

In the 2025 ESOO, AEMO modelled the impact of risk sensitivities and reported:

Figure 11: Forecast unserved energy under committed and anticipated developments scenario 2025–26 to 2034–35

Note: Gas shortfalls and drought sensitivities build on the generator maintenance sensitivity.
Source: VAGO, based on AEMO’s 2025 ESOO workbook.

In the 2025 ESOO, AEMO also forecasts unserved energy under a government schemes and actionable developments scenario. 

This scenario forecasts that the risk of electricity shortfalls will be within the reliability standards to 2034–35 (see Figure 12). 

But it assumes all government schemes and projects meet target dates. In some cases, target dates may reflect optimistic scenarios and may not reflect the latest information. For example, this scenario assumes 2 GW of offshore wind capacity will be available by 2032. But this will take until at least 2033, if there are no further delays.

Figure 12: Forecast unserved energy under government schemes and actionable developments scenario 2025–26 to 2034–35

Note: Gas shortfalls and drought sensitivities build on the generator maintenance sensitivity.
Source: VAGO, based on AEMO’s 2025 ESOO workbook.

So while Victoria’s reliability outlook has improved, there is still a risk of near-term electricity shortfalls when Yallourn closes. 

The extent of risk will become clearer as the progress of CIS-supported projects becomes evident. Importantly, the Australian Minister for Climate Change and Energy announced Victorian projects for:

• 0.6 GW of 4-hour duration equivalent storage in December 2024 
• 1.6 GW of renewable generation capacity in December 2024 
• 1.3 GW of 4-hour duration equivalent storage capacity in September 2025
• 1.2 GW of renewable generation capacity in October 2025.

Projects that are targeting commissioning in the 2030s are less likely to meet AEMO’s criteria relating to planning, construction, land, contracts and financing, to qualify as a committed and anticipated development. However, AEMO’s forecasts for 2030–31 to 2034–35 predict substantial electricity shortfalls against reliability standards under the current committed and anticipated developments pipeline of projects, as Figure 11 shows. These shortfalls exceed those AEMO published in its 2024 ESOO because of an upwards revision to forecast electricity demand (see Figure 13).

This highlights the need for continued private investment and government action to secure Victoria's electricity supply as coal-fired power stations close. These forecasts do not yet reflect the scheduled Loy Yang A closure by 1 July 2035. 

Figure 13: Forecast electricity shortfall under the committed and anticipated developments reliability assessment in the 2024 and 2025 ESOOs 

Note: The ESOO provides a 10-year outlook. There is only one bar in 2034–35 as the ESOO 2024 only provided forecasts to 2033–34.
Source: VAGO, based on AEMO's 2024 and 2025 ESOO workbooks.

Coal’s exit

The Victorian Government negotiated structured transition agreements with the operators of Yallourn and Loy Yang A to close by 30 June 2028 and 1 July 2035 respectively.

As part of its advice on the timing of the closures, the department commissioned modelling to give assurance that new renewable energy projects would offset the closures.

Advice in 2020 estimated that closing Yallourn would lead to a firm energy gap of 1.37 GW during a summer peak demand event lasting longer than 2 hours. 

The advice made several assumptions about new infrastructure and future demand and how these factors may offset the closure of Yallourn.

We replicated the department’s 2020 analysis using the same method and current information on proposed projects. 

We estimate a firm energy shortfall of 891 MW against the department’s advice (see Figure 14). 

AEMO data indicates there could be up to 4,505 MW (or 10,453 MWh) of additional battery storage capacity available in Victoria by winter 2028. This includes phase one of the Melbourne Renewable Energy Hub, which will deliver 600 MW (or 1,600 MWh) of storage capacity. These projects will add to the Wooreen battery and VRET2 batteries.

With a 2-hour window as per the department’s analysis, this battery capacity will more than offset Yallourn's closure.

Figure 14: Estimated firm energy gap after Yallourn closes

Note: Based on a summer peak demand event lasting longer than 2 hours. FY29 means financial year 2028-29.
Source: VAGO, based on the department’s methodology, analysis of the Yallourn structured transition agreement and AEMO data.

Demand may exceed supply for periods longer than 2 hours. During these periods, the pipeline of 2-hour and 4-hour batteries might not be enough to offset Yallourn's closure and other sources of electricity may be required to ensure a reliable electricity supply.

In 2021, the department commissioned modelling to examine the impact of closing Loy Yang A and Loy Yang B during a summer peak demand event lasting longer than 2 hours. The report estimated the:

• firm energy gap in 2035 if both or either plant closes
• added capacity needed to ensure reliability. 

The report found that forecast growth in renewable electricity generation and the completion of VNI West and Marinus Link Stage One and Stage Two can offset Loy Yang A's 2035 closure. 

It is still too early to assess if the assumed growth is likely and when Marinus Link will be in service.

Weather variation

AEMO has stated that weather variation, such as extended dark and still weather conditions, will pose significant challenges to electricity supply.

AEMO has stated that a reliable electricity system needs to have an extra level of reserve energy, over and above the level of electricity demand at any given time, to act as a buffer to meet challenging conditions.

We requested that the department provide analysis of potential electricity supply issues during unusually prolonged dark and still periods in winter. The department did not provide this analysis.

Therefore, we used data from 29–30 July 2024 as an indicative case study to understand the possible impact on electricity supply of severe dark and still weather conditions after Yallourn closes. 

On these days there was a high-pressure system over south-eastern Australia, resulting in low wind. Solar output was also low given the time of year. Victoria relied heavily on coal, gas, hydro electric and batteries to meet demand. This infrastructure ran close to full capacity but there was still tight supply, particularly during the evening peak.

As it is reasonable that these conditions will recur, we modelled whether the electricity system could meet Victoria’s demand under identical conditions immediately after Yallourn closes.

This differs from AEMO’s modelling approach. AEMO conducts simulations, based on its supply assumptions, to estimate probability-weighted average unserved energy for a year.

We considered 2 demand growth scenarios:

• the 2025 ESOO forecast for 5.5 per cent growth in demand
• a 10 per cent probability of exceedance winter demand.

We examined if potential projects with a start date prior to July 2028 and an expansion in generation from existing assets would offset Yallourn’s closure and address overnight gaps (see Figure 15). 

There are up to 11,400 MWh of committed, anticipated and proposed battery projects that may come online by July 2028 and around 3,000 MWh of electricity could come from other states overnight. If there is enough gas supply, gas-powered electricity generation could run at high capacity overnight. 

But hydro-electric generation already ran all day, meaning that water supply, pumping and downstream constraints could limit the ability of hydro-electric to address the overnight gap.

If all other things are held constant, this results in an estimated overnight gap of around 2,720 MWh or an average firm capacity gap of around 182 MW under the ESOO demand forecast and around 11,240 MWh or 700 MW under the 10 per cent probability of exceedance scenario.  

We have assumed significant growth in gas generation in response to supply issues. If a further sustained increase in gas generation is feasible, this may address or lessen the gap. However, it is not clear this is feasible given the age of Victoria’s gas plants and forecast gas supply issues. 

Our analysis does not factor in supply issues such as asset outages, project delays or higher demand than forecast. These could contribute to larger firm capacity gaps. 

But our analysis shows that Victoria faces tight electricity supply as coal exits, even under an optimistic scenario of new project entry. In overnight, still periods when renewable generation is low, this could mean electricity demand exceeds supply.

Addressing firm capacity gaps

In our case study example in Figure 15, we assume that:

• gas-powered electricity generation output peaks at 1.5 GW
• hydro-electric generation peaks at 1.5 GW
• Victoria imports an hourly average of 200 MW of electricity from interstate.

Victoria currently has up to:

• 2.4 GW of gas-powered electricity generation capacity
• 2.3 GW of hydro-electricity generation capacity
• 2.9 GW of transmission import capacity. 

But operational constraints mean it is unlikely that these sources will be able to operate near their maximum capacity by 2028. They are unlikely to deliver the firm energy Victoria may need under overnight cold and still weather conditions.

Figure 16: Actual and forecast peak day gas demand and supply in Victoria 

Note: Chart displays AEMO peak day forecasts for high-demand days from the Victorian Gas Planning Report. AEMO has noted that seasonal peak gas generation has the potential to coincide with a peak system demand day, especially during winter. 
Source: VAGO, based on AEMO actual data and forecasts from the Victorian Gas Planning Report.

AEMO has an obligation to ensure gas demand does not exceed supply. This is to meet pipeline pressure and safety standards and to avoid extended gas pipeline restart processes. If the gas supply was interrupted, it could take days before access is returned and gas can be used again.

It is difficult for AEMO to limit household and business gas usage. If there is a gas shortage AEMO may need to limit gas-powered electricity generation by up to 498 TJ per day to balance supply and demand. 

This could mean that Victoria’s gas-powered electricity generators can only operate at 6 per cent of the required capacity on high-demand days.

Even in a lower-demand scenario and a mild winter, forecasts suggest that gas-powered electricity generators could only be able to operate at 26 per cent of the required capacity at peak times.

AEMO forecasts suggest gas supply could get worse in 2029, leading to more firm energy capacity gaps. AEMO may need to undertake significant load shedding and a substantial proportion of electricity customers could experience overnight blackouts.

This also does not factor in higher-than-anticipated household and business gas use. AEMO assumes that households and businesses will reduce their peak gas usage by 12 per cent (140 TJ per day) by 2029. This reflects government interventions to reduce gas demand under the Gas Security Statement and Gas Substitution Roadmap and their potential impacts, including:

• new requirements for new homes and government buildings to be all-electric from 2024, with no gas connection
• changes to the Victorian Energy Upgrades program from 2023, including removing gas appliances, and new incentives for switching from gas to electric appliances.

But AEMO forecasts that gas supply will fall 31.7 per cent (400 TJ per day) by 2029 because of a fall in gas supply from Gippsland. This means forecast gas supply is significantly less than demand.  

While the department has advised the government on gas supply risks, it is not clear to what extent responses will address forecast shortages. 

National energy ministers are currently considering a potential amendment to AEMO's powers to bolster east-coast gas supply.

Hydro-electricity constraints

On 29 July 2024, Victoria’s hydro-electricity output reached one of its highest levels. The total output was 18.1 GWh from 9 am to 9 am between 29 and 30 July 2024, with maximum output reaching 1.5 GW.

In our scenario, we did not assume more hydro-electricity output than 18.1 GWh because of operational and water-licensing constraints at Victoria’s largest hydro-electricity power stations, Murray 1 and 2. 

These stations provided 89.7 per cent (16.2 GWh) of Victoria’s hydro-electricity supply from 9 am to 9 am between 29 and 30 July 2024.

Murray 1 and 2 rely on pumping water from Lake Jindabyne to Geehi Reservoir before releasing it downstream to power the stations’ turbines. On any given day, hydro-electricity output from Murray 1 and 2 production is limited by:

• pumping limits under the Snowy Water Licence 
• the total water volume available in Geehi Reservoir and downstream capacity. 

When Geehi Reservoir is full, Murray 1 and 2 can operate at maximum capacity for around 14 to 16 hours under normal conditions.

Up to 13 GWh of additional electricity could be provided overnight if AEMO directed Murray 1 and 2 to run overnight at their maximum output and there was sufficient downstream capacity. It would also need to be allowed under the Snowy Water Licence. 

This level of output would be significantly higher than the highest water use and generation previously delivered by Murray 1 and 2. 

But it would only address around 43 per cent of the estimated overnight firm capacity gap under the 10 per cent probability of exceedance winter demand scenario (30 GWh). Fully covering the gap in 2028 would still require: 

• gas-powered electricity to be generated overnight at its highest level (providing an added 6 GWh) 
• sufficient electricity to import from other states overnight (providing 3 GWh)
• planned battery projects commissioned before 30 June 2028 operating at high capacity to deliver 9 GWh overnight.

This would also reduce water storage in the Geehi Reservoir. While additional water could be pumped from Lake Jindabyne during the day, lower water storages would limit the capacity of Murray 1 and 2 compared to the previous night.

If Victoria experienced a second night of similar low-wind conditions, it would have lower hydro electric capacity and its dependence on already constrained gas-powered electricity generation and interstate electricity imports would increase.

Other factors that could limit overnight hydro-electricity output include:

• below-average seasonal rainfall or changes in channel capacity
• network security issues
• any planned or unplanned maintenance and outages.

Electricity import constraints

On 29 July 2024, Victoria exported electricity interstate despite constrained supply, including overnight (1.7 GWh). 

During winter nights where there has been one or more coal unit outages in Victoria, the state has continued to export electricity overnight 82.8 per cent of the time. 

During these nights, Victoria was a net overnight importer of electricity from interstate only 17.2 per cent of the time. On only 6.5 per cent of these nights, has Victoria imported more than 4 GWh net overnight (see Figure 17).

Figure 17: Histogram of net overnight electricity imports during winter coal outages May 2023 to August 2025

Note: Columns represent the frequency that net overnight imports fell within specific ranges, denoted on x-axis labels that display the midpoints of those ranges. For example, the 2 GWh column displays the % of the time that net overnight electricity imports ranged from 0 to 4 GWh, while the right-most column includes all outcomes greater than 8 GWh.
Source: VAGO, based on AEMO NEM data.

In our scenario, after Yallourn’s scheduled closure, we assumed that Victoria could import 3 GWh overnight to help address firm capacity gaps.

Victoria’s transmission assets’ maximum import capacity is 2.9 GW. In theory, if other states have enough electricity, Victoria could import up to 44 GWh overnight. This would be more than enough to address our estimated firm capacity gaps. 

But Victoria’s net overnight imports during winter outages only exceeded 10 GWh one per cent of the time with a 12 GWh maximum. There is no guarantee Victoria will be able to rely on high overnight imports during cold, dark and still conditions. 

Other states could face similar conditions, which could limit electricity generation across south eastern Australia. This would limit other states’ electricity export capacity.

For example, in winter, high-pressure systems often pass over south-eastern Australia. This means New South Wales, South Australia and Tasmania experience reduced wind speeds at the same time as Victoria (Figure 18).

Wind turbines do not generate electricity at speeds below 10 kilometres per hour. In 2024, Victoria faced 35 days from 1 June to 31 August with afternoon wind speeds below 10 kilometres per hour. 

Victoria also faced a 27-day stretch of low-wind conditions in May 2024 and an 11-day stretch in April 2024.

Figure 18: Average wind speed in south-eastern Australia at 3 pm between 1 May and 31 July 2024

Note: Chart presents Bureau of Meteorology average wind speeds recorded by weather stations at 3 pm. 
Source: VAGO, based on Bureau of Meteorology data for Melbourne, Adelaide, Canberra (proxy for New South Wales wind farm conditions) and Hobart stations.

Figure 18 shows that other states also experienced low-wind conditions between 29 and 30 July 2024, leading to overnight demand for imports from Victoria during this time. 

This means that Victoria's ability to import electricity will depend on the overall availability of dispatchable power resources across south-eastern Australia.

However, low wind or solar could also reduce battery storage and output. Low rainfall could reduce hydro electric imports from Tasmania and New South Wales.

AEMO and the Australian Competition and Consumer Commission have also forecast gas shortages across all south-eastern states, which could limit gas-powered electricity generation outside of Victoria (see Figure 19). 

Figure 19: Forecast peak day gas demand and supply across Victoria, New South Wales, South Australia and Tasmania 

Note: Chart displays AEMO peak day forecasts for high demand days from the Gas Statement of Opportunities. AEMO has noted that seasonal peak gas generation has the potential to coincide with a peak system demand day, especially during winter.
Source: VAGO, based on AEMO forecasts from the Gas Forecasting Data Portal and the 2025 Gas Statement of Opportunities.

The upcoming closure of coal and gas-powered electricity plants in New South Wales and South Australia could also mean that these states face tight electricity supply, which would constrain their export capacity. 

Despite New South Wales and South Australia bringing on additional battery capacity, several plants will stay open beyond their originally planned retirement dates. This includes the Eraring coal-fired power station in New South Wales and the Torrens Island gas-fired power station units in South Australia, which account for 2.9 GW and 600 MW of firm capacity respectively (see Figure 20).

Overall, the closure of key coal and gas-fired power stations in New South Wales and South Australia will reduce their firm capacity by 4 GW by Yallourn’s scheduled closure date.

Figure 20: Closures of coal and gas-fired power stations in New South Wales and South Australia, over 50 MW

Source: VAGO, based on AEMO NEM Generation Information and Generating Unit Expected Closure. 

Victoria’s CIS allocation 

CoUnder the Australian Government–Victoria Renewable Energy Transformation Agreement, Victoria has secured an allocation under the CIS to fund at least:

• 11 TWh of variable renewable electricity generation projects, comprising 3.5 GW of wind and 1.5 GW of utility-scale solar projects
• 1.7 GW or 6.8 GWh of 4-hour equivalent battery storage projects.

Tender guidelines state a preference for projects that can be operational by 31 December 2029.

The department has calculated that Victoria’s CIS allocation accounts for most of the required additional generation to meet Victoria’s 2030 65 per cent renewable energy target.

The department’s advice indicates that the additional generation and storage will maintain electricity reliability in 2030. The department has indicated that this is robust for different scenarios that it has modelled, including gas supply uncertainty and asset outages.

Project delays remain a risk. The commercial operating date for several CIS-supported projects is the end of 2029. However, renewable energy projects in Victoria have faced delays, including because of challenges connecting to the transmission network. 

Safeguarding near-term reliable electricity in Victoria

Potential reliability gaps in Victoria's near-term electricity supply are the result of Yallourn closing, higher-than-expected electricity demand and insufficient action by private investors and the department to bring on new supply.

AEMO’s government schemes and actionable developments scenario forecasts that Victoria’s allocation under the CIS and other government and transmission projects will contribute to reliability if projects come online in 2028–29 and 2029–30. If projects face delays, AEMO may need to safeguard reliable electricity in Victoria. 

Under the National Electricity Law and National Electricity Rules, AEMO has operational responsibility for electricity reliability across the NEM. In managing forecast reliability gaps, AEMO can:

• request the Australian Energy Regulator to trigger the Retailer Reliability Obligation (RRO) to require energy retailers and large energy consumers to enter contracts to cover their portion of peak demand in advance of periods with a forecast reliability gap
• procure and activate emergency out-of-market electricity reserves through the Reliability and Emergency Reserve Trader mechanism when the RRO is insufficient
• direct generators and other NEM participants to take actions to maintain power system security and reliability.

At AEMO’s request, the Australian Energy Regulator triggered an RRO to address shortfalls it forecast for 2027–28 in the 2024 ESOO. However, as AEMO did not forecast these shortfalls in its 2025 ESOO, the RRO may be revoked.

The RRO aims to encourage electricity retailers to support investment in new electricity projects. However, there are constraints that increase the likelihood that retailers will need to purchase from existing generators.

AEMO and the Australian Energy Market Commission have stated that the current design of the RRO is unlikely to promote the required new investment in electricity generation capacity. 

The first trigger under the RRO is the T-3 instrument, which alerts electricity providers to purchase enough wholesale supply to cover a forecast gap. The Australian Energy Regulator issues a T 3 instrument 3 years before the forecast reliability gap period.

Three years is not likely to be a sufficient length of time to signal new investment in many types of capacity. This is because pre-construction activities, such as reaching the final investment decision and finalising contracts, and construction and commissioning, generally take longer than 3 years.

The RRO and Reliability and Emergency Reserve Trader mechanism also place upwards pressure on electricity costs, which retailers or AEMO pass on to consumers. This would be in tension with the Victorian Government's commitment to provide affordable electricity for all Victorians.

Planning for risk and uncertainty 

Department of Treasury and Finance guidelines for high-value and high-risk investments state that agencies should factor risks and uncertainties into problem definition, analysis and modelling. 

This helps agencies to understand the nature of a problem, identify options, and estimate costs and benefits. It also provides flexibility to respond to risks and uncertainties.

Demand uncertainty

Energy forecast accuracy is important for developing policies that allow for a smooth transition to renewable energy. The department relies on AEMO's forecasts to understand future demand.

AEMO’s forecasting method meets requirements under the National Electricity Rules and its forecasting safeguards meet the Australian Energy Regulator's Forecasting Best Practice Guidelines. 

AEMO assesses and reports the accuracy of its prior year’s forecasts over the most recent year.

AEMO does not report on the long-term accuracy of its forecasts but regularly updates them to improve accuracy.

For example, AEMO’s 2022 Integrated System Plan forecast that electricity demand in Victoria would fall by 1.8 per cent in 2024–25. But demand grew by 3.5 per cent annually. AEMO revised its forecasts in recent years based on electricity demand growing faster than expected and the latest information (see Figure 21).

Figure 21: AEMO’s revised electricity demand forecasts

Note: ISP stands for Integrated System Plan. NEFR stands for the National Electricity Forecasting Report.
Source: VAGO, based on AEMO’s Integrated System Plan and National Electricity Forecasting Report documents.

AEMO's revisions improve the department’s and investors' understanding of long-term electricity demand in Victoria. But significant demand revisions make it difficult for long-term planning to ensure that enough generation and storage capacity is in place while minimising cost.

For example, when the department advised the government on setting renewable energy targets in 2017, it relied on AEMO’s flat electricity demand forecast to 2030. The department then extended this out to 2050. Since then, AEMO has forecast that Victoria’s electricity demand will grow 84.3 per cent by 2050. 

Even between 2024 and 2025, rising demand forecasts led AEMO to widen forecast reliability gaps under the committed and anticipated pipeline of energy projects from 2030–31. This is despite more renewable generation and storage capacity being added to the system.

While AEMO expects government renewable schemes and developments to cover reliability gaps, this highlights how there is little margin for error. It is important that planning ensures a buffer for higher-than-expected demand.

AEMO also reported inaccuracy in its forecasts of peak winter demand in Victoria. For example, in June 2025 there was record winter peak electricity demand – around 7 per cent higher than AEMO forecast in its high-demand scenario in the 2024 ESOO.

Planning for Victoria's renewable energy transition

AEMO has reported a forecast risk of a reliability gap coinciding with Yallourn’s exit since 2021. 

Current forecasts show that private investment and the department’s planning and market facilitation are on track to address the gap but there is little margin for risk.

The department has not always factored key risks and uncertainties into advice around key decisions for Victoria’s renewable energy transition (see Case study 1).

Case study 1: Closing Yallourn

The setting of offshore wind targets in 2022 was also based on a single scenario that did not factor in risks (see Case study 2).

Case study 2: Offshore wind

Planning in 2022 for offsetting the closures of Loy Yang A and B from 2035 also made optimistic assumptions about the availability of long-duration storage, which is now unlikely (see Case study 3).

Case study 3: Long-duration storage projects

The Victorian Transmission Plan

To date, transmission limitations have been a challenge for renewable energy projects in Victoria.

VicGrid released the first Victorian Transmission Plan in 2025. It outlines a transmission and renewable generation strategy to 2040 to meet Victoria’s electricity needs as coal plants close.

In developing the plan, the department modelled:

• which areas of Victoria are most suitable for renewable energy generation, proposing 7 renewable energy zones
• how much wind and solar energy each zone should generate
• the additional or upgraded transmission infrastructure to connect the volume of potential electricity generation and storage projects to the grid.

To encourage market investment, VicGrid proposes that projects within renewable energy zones will have more certain network access and less risk of curtailment.

Proposed transmission development pathways 

The Victorian Transmission Plan presents 3 potential scenarios and a transmission infrastructure development pathway for each. These are:

1. for AEMO’s step-change scenario
2. for a higher-demand scenario where new energy-intensive industries establish in regional and central Victoria at scale (such as data centres, hydrogen production and green aluminium)
3. for AEMO’s step-change scenario with one-year delays to offshore wind, the Western Renewables Link, VNI West, Marinus Link Stage One and no Marinus Link Stage Two.

Pathway 1 proposes 7 projects to upgrade or to develop new transmission infrastructure. The development pathways for scenarios 2 and 3 build on pathway 1 with additional projects to help meet the higher demand.

VicGrid chose development pathway 1 as the optimal pathway given the 3 scenarios via 'least worst regrets' analysis.

Based on current information, the delayed scenario appears more likely than AEMO’s step-change scenario. For example, the department has already advised government of delays to offshore wind, with the Western Renewables Link and VNI West already delayed.

AusNet has also stated that there are data centres requiring more than 10 GW of electricity in development in Victoria. If approved, these could increase electricity demand above Victoria’s current supply capacity. AEMO is analysing demand growth and included forecasts of electricity demand from data centres in the 2025 ESOO.

Assumed new generation capacity

The Victorian Transmission Plan assumes 19.5 GW in new generation and storage capacity between 2025–40 to meet government targets, reliability standards and offset coal closures. This will require commissioning 1.3 GW of new renewable projects per year on average, against the 0.5 GW per year seen since 2010.

The Victorian Transmission Plan also assumes that AEMO will commission 4.1 GW in new onshore wind and solar capacity by 2028–29. This would be a 70.7 per cent increase on current capacity, which is double the growth from 2020–21 to 2024–25. 

If conditions are different to the assumptions, this could result in lower growth in electricity supply and an increase in the risks.

Transmission infrastructure in northern and western Victoria is at capacity, which is delaying new projects connecting to the network. 

The Victorian Transmission Plan proposes that the first 2 transmission projects in the optimal development pathway will come online in 2028 and 2029. Existing capacity issues and potential project delays could mean the existing transmission network does not support an additional 4.1 GW of new generation capacity. With the delays to the Western Renewables Link and VNI West, this could leave insufficient transmission capacity to offset Yallourn’s closure by 30 June 2028.