It is one of the central pillars of Australia’s broader Net Zero strategy, with the success or failure of the entire transition to net zero largely dependent on the success of this one sector.
However, it is not clear if the necessary changes in how electricity is generated, stored, transmitted and dispatched will happen fast enough, or whether practical challenges will slow progress toward net zero, given the complex nature of Australia’s current energy landscape and existing dependencies.
As such, whilst the Australian Government’s ambition to meet our Net Zero commitments is admirable, the planning falls short.
The EESP focuses on three system‑wide shifts:
Using energy more efficiently.
Electrifying and fuel‑switching where possible
Scaling up clean energy supply such as renewables, storage, renewable gases and low‑carbon liquid fuels.
Funding
- $1.1bn to build a supply chain for LCLF
- Clean Energy Finance Corporation (CEFC)
- $50m to make energy efficient community sports clubs
- $2bn now + up to $2bn later for rapid rollout of renewable projects
- $1bn to support domestic solar PV manufacturing
- Australian Renewable Energy Agency (ARENA)
- $85m to accelerate energy performance
- Greenhouse and Energy Minimum Standards Program; Commercial Buildings Disclosure Program; National Australian Built Environment Rating System and Nationwide House Energy Rating Scheme; AEMO
- $40m to accelerate EV charging infrastructure rollout
Who is impacted by the Resources Sector Plan?
Stable, secure and reliable energy is a vital modern-day requirement for every developed nation. And so, the impacts of this sector plan will ripple across government, industry, communities and households.
The energy sector shoulders much of the burden, as electrification policies underpin decarbonisation efforts in nearly every other sector. Governments provide direction, utilities and infrastructure providers bear execution risk, industry faces major capital decisions, communities host the physical footprint of the transition, and consumers ultimately pay for and depend on the outcome.
Government and regulators sit at the centre of the plan, with responsibility split between federal targets, state‑based delivery and a complex web of agencies and market bodies. Amit Kabra, National Government and Public Sector Leader, RSM Australia has observed the friction between different levels of government, leading to uneven progress between states. At a national level, the federal government’s commitment is “rock solid,” Kabra says, while noting that with state governments, “there are some wobbly parts.” Queensland’s retreat from earlier renewable targets are a clear example of this tension.
Note. Reprinted from Electricity and Energy Sector Plan (p. 17), by Department of Climate Change, Energy, the Environment and Water, 2025, https://www.dcceew.gov.au/sites/default/files/documents/electricity-energy-sector-plan-2025.pdf
The absence of one overarching player is an issue, making coordination difficult and complicating accountability when projects are delayed or targets slip.
Transmission network operators and infrastructure developers are key stakeholders in this plan. The EESP assumes a vast expansion of transmission to connect widely distributed renewable generation assets to our major cities, where much of the demand exists. Jacob Elkhishin, National and Global Leader ESG Services, RSM points to finance as the major barrier to grid upgrades.
“A lot of the infrastructure operators or owners of electricity networks are still state owned,” he says, which means the costs have to come out of each state’s budget.
Regional communities and landholders are also impacted as much of the infrastructure required for the transition, like wind farms, solar farms and transmission lines, must be built in regional areas. Craig Amos, National Energy and Resources Leader, RSM believes that while there is broad support for net zero, many people do not fully understand “what it means in terms of the environmental and visual impact associated with large-scale wind farms and thousands of kilometres of new high-voltage transmission”.
This is a social licence issue, where community opposition may delay or derail projects, even when they are critical to national targets.
Energy generators and utilities are among the most directly affected. They are expected to retire ageing coal‑fired assets, invest heavily in renewable generation and increasingly take on system-stabilising roles once performed by large coal and gas generation assets.
Craig Amos highlights that while renewable generation assets are “relatively inexpensive to build,” government and utilities face a different reality when judged on what he terms the “all‑in levelised cost across the system to deliver energy to consumer,” which includes transmission, storage and grid integration. Utilities must therefore manage rising capital expenditure while operating in markets that are experiencing significant price volatility.
Large industrial energy users face profound impacts, both as consumers of electricity and as contributors to demand growth. Amos singles out the growth of energy-intensive data centres needed for cloud computing and the AI boom, Australia’s critical mining industry and heavy industrial users as key stakeholders on the demand side.
For energy‑intensive industries such as aluminium and steel, electricity is only part of the equation. They need the heat from fossil fuels burning, meaning electrification implies significant capital expenditure to refit existing plant and equipment.
Gas producers and the gas market are also deeply implicated. Amos describes gas‑fired power as essential both for replacing coal capacity and system stability and reliability while utility-scale batteries are built out.
This is placing pressure on Australia’s east‑coast gas market, where almost all of the gas supply infrastructure has been funded by international consortiums who then export it - drawing gas producers, international investors and governments into contentious debates over gas reservation policies.
Residential consumers and households ultimately feel the plan most directly. Although the EESP suggests significant long-term savings for households, in the near term, the cost will mainly be borne on the consumer.
In addition, any essential infrastructure that cannot be funded by the private sector must instead be paid for by taxpayers.
The broader economy and future industries are also indirectly impacted in terms of Australia’s energy security.
In Craig Amos’s view, energy security is “one of the top three current global geopolitical issues,” pointing to the ongoing impacts of war in Ukraine and, more recently, Iran and other regions.
Reliable, affordable energy underpins everything from households to export industries and, increasingly, large data centres and computing power for AI and the cloud.
Decisions made under the sector plan therefore shape Australia’s attractiveness for future investment, including advanced manufacturing and digital infrastructure, with significant impacts on the everyday life of Australians.
82% renewable electricity by 2030
Reaching 82 % renewables by 2030 will require 35GW new grid-scale wind and solar.
The Australian Energy Market Operator (AEMO) draft 2026 Integrated System Plan (ISP), due to be published in June 2026, says that grid-scale wind and solar capacity is currently 23GW.
That needs to reach 58GW by 2030.
However, as the CCA points out, “In 2024-25, 1.5GW of solar and 1.4GW of wind generation were fully commissioned in the National Electricity Market (NEM).”
That is a jump from a higher than average ~3GW added in 2024-25 to 8.7GW added per year.
Capacity, NEM (GW, 2009–10 to 2049–50, Step Change)
Note. Reprinted from 2024 Integrated System Plan (p. 11), by Australian Energy Market Operator, 2024, https://www.aemo.com.au/-/media/files/major-publications/isp/2024/2024-integrated-system-plan-isp.pdf
This assumes a massive uptick in wind and utility solar.
Although the draft ISP 2026 does not project any offshore wind coming online before 2030, post-2030 projections still include a rising share of offshore wind power.
A look at the number of abandoned offshore wind projects courtesy of reneweconomy.com’s RenewMap highlights why depending on offshore wind (and to a lesser extent hydrogen) is risky.
Expanded firming capacity
There are currently 24-27GW wind and solar projects in progress and 25GW of dispatchable grid-scale storage projects in the connection pipeline.
However, historic challenges indicate that there may be significant delays in bringing projects online. While generators and batteries are relatively quick to build, they often face a year and a half of sensitivity testing before entering the grid.
Connecting to the grid is an issue Craig Amos has observed impact several renewable energy developers and constructors, describing how a typical 150MW renewable energy power project can be built in under 12 months, but could face up to two years to commission onto the grid. It highlights that whilst renewable generation projects can be built and added to the system relatively quickly, the required grid stability, storage and transmission infrastructure needed to commission these projects is simply not there yet.
RenewEconomy. (n.d.). RenewMap. https://reneweconomy.com.au/renewmap/
The slow speed of uptake of new technology is clearly reflected in the energy market.
Nicole Mohan
Nicole Mohan, Partner, ESG Services, RSM Australia, shares her experience performing audits for the clean energy regulator which often require site visits to power stations.
She says, “We’ve been doing these type of audits since 2010. It’s only this year, 2026, where we’ve seen ones with battery storage capabilities.” Even then, they’re rare, with only one out of six organisations having power stations with batteries.
Gas will continue to play a key role in Australia’s energy mix, particularly as aging coal plants are decommissioned. Amos notes that nuclear options remain “off the table” politically in Australia, making it one of only a small number of OECD countries not considering nuclear in the energy mix in some capacity.
Natural gas will therefore for the foreseeable future continue to act as the default firming technology, ensuring that electricity remains available when intermittent renewables cannot meet demand.
“One of the other benefits of large gas‑fired power stations is it acts as the stabiliser of the grid while we’re building out utility-scale battery storage,” Amos says.
At the same time, gas introduces political and economic risk into the transition. Australia produces large volumes of gas, but on the east coast where there is no domestic reservation policy, much of it is tied up in foreign investment and export offtake contracts. This makes it difficult to guarantee domestic supply at predictable prices.
Craig Amos
The east coast also has gas infrastructure challenges, which Craig Amos explains:
“While Queensland has the bulk of active east coast gas production assets, the bulk of the demand is in New South Wales and Victoria which have little local gas production capacity.”
An ominous consequence of the above is that the east coast of Australia may become an importer of gas (possibly from nations with less ambitious net zero plans), which is difficult to understand given Australia’s abundance of gas resources.
These constraints are confirmed in AEMO’s 2025 Transition Plan for System Security, where it states “GPG is expected to be increasingly relied on for firming capacity and will remain critical for system security. However, gas adequacy and pipeline capacity constraints – particularly in southern regions – will need to be addressed so that locational flexibility for new developments is not restricted. The 2025 GSOO projected tightening gas supply in the upcoming years, with gaps emerging from 2028 onward, signalling the need for new fuel supply and infrastructure investment.”
Despite the need, there is little appetite to build new gas infrastructure. The CCA says that global demand for gas-fired power stations is causing delays of up to seven years for new builds, adding constraints to delivery timelines. And so long as gas is treated as a temporary solution on the way to net zero, any new assets risk being stranded or retired early, making new builds risky for investors under current policy settings.
In addition, the EESP assumes that green hydrogen and biomethane will account for over 30% of peaking fuel (the fuel used by power plants that run only during periods of high demand) by 2035, but offers no price floor mechanism, like the EU’s Contract for Difference (CfD) for renewable fuels of non-biological origin (RFNBOs). It is also unclear where this green hydrogen and biomethane will be supplied from. Without a clear and workable natural gas strategy, the plan’s timelines appear increasingly fragile.
Network infrastructure and energy security
Grid stability and transmission remain key concerns in managing Australia’s energy transition. AEMO estimates we will need 6000km of new transmission by 2050, which it labels a reduction from the previous estimate of 10,000km.
However, that modelling draws a distinction between “transmission network” and “connection assets” (a term not used in the 2024 ISP), obfuscating that the estimated amount of new transmission is largely the same.
The 2026 draft ISP calls for between “5,000 km and 7,000 km of new transmission network investment” and “between 1,000 km and 3,000 km of connection assets,” which puts the total transmission required between 6,000km and 10,000km, or 8,000km in the step change scenario.
Note. Reprinted from Draft 2026 Integrated System Plan (Figure 2), by Australian Energy Market Operator, 2025, https://www.aemo.com.au/-/media/files/major-publications/isp/draft-2026/draft-2026-integrated-system-plan.pdf
The distinction is that connection assets are privately owned, existing to connect generators to the shared transmission grid, rather than being part of it.
This places an additional burden on private investors to pay for and deliver infrastructure that Australia needs. As investor enthusiasm for renewable projects wanes, adding additional upfront capex is likely to prove a market deterrent.
In addition, concerns persist around the delivery timelines and real cost inflation of existing transmission projects.
According to Craig Amos, “The challenge to net zero is not so much a question of will we have enough renewable generation given the relative ease to build new wind and solar projects. It’s will we have enough transmission to get a watt from widely distributed locations to a capital city, and secondly, can it actually be stored and transmitted safely?” In his view, transmission and stabilising technologies (such as utility scale batteries) are not keeping pace with the rate renewable generation assets are being introduced into the energy system, leaving Australia with a more vulnerable and unstable energy system.
There are other more optimistic perspectives, with some highlighting technology solutions such as virtual power plants and synthetic inertia from asynchronous generators as support for grid stability. The real challenge, according to some of them, will be the initial capital expenditure and market confidence around pricing and return on investment. Some say they have started to see negative pricing happening on the grid, which has forced wind turbines and solar farms to turn off and not enter the grid. This means that there's a lot of money lost.
Cost implications of Australia’s energy transition to net zero emissions
While governments set ambitious targets and rely on markets to deliver the required infrastructure, the end costs are most visible in the rising electricity bills of everyday households.
CSIRO modelling that calculates energy transition costs in dollars per megawatt-hour (MWh) reveals that promises of a low-cost energy future delivered via net zero are simply untrue. In all scenarios, the Australian price of electricity increases as emissions decrease.
This is amplified by frequent budget overruns in transition projects, which regulators historically pass on to consumers, further increasing costs.
For industrial users, costs rise in different ways. Heavy industries and data centres face the challenge of securing reliable, affordable power in a system under stress.
Craig Amos notes that mining and industrial processing facilities require hundreds of megawatts of stable energy supply, and power prices directly affect their global competitiveness. Sectors like aluminium and steel rely not just on electricity, but on fossil‑fuel‑based heat, meaning decarbonisation demands huge capex to upgrade or replace existing equipment.
Commonwealth Scientific and Industrial Research Organisation (CSIRO). (n.d.). CSIRO Data Access Portal (Data set csiro:44228). https://data.csiro.au/collection/csiro:44228
Opportunities, financial incentives and funding pathways
Bankability has emerged as the biggest constraint on progress for Australia’s energy transition. Across generation, storage and transmission, private capital is increasingly willing to fund assets that can be built quickly and operated efficiently. However, it understandably pulls back when projects are exposed to system‑level and regulatory risks that sit outside a proponent’s control.
Private finance requires revenues to be contractually locked in, connection risk to be manageable, and commissioning timelines to be predictable. That model begins to break down as electricity systems become more congested and complex. Market volatility, curtailment and negative pricing now materially affect project economics, particularly in regions with weak grid infrastructure or limited transmission capacity.
This is where government increasingly steps in: not to replace private capital, but to absorb risks that markets cannot efficiently price.
The CIS is the most significant intervention currently shaping new investment in the energy market. It operates as a form of long‑term revenue underwriting, reducing exposure to merchant risk where private offtake is insufficient or too volatile to support financial close.
The CIS acts as a synthetic power purchase agreement when private offtake is unavailable or too risky. By stabilising revenues, the scheme allows otherwise viable projects to proceed. Importantly, CIS support is not allocated solely on the basis of capacity additions, but on contributions to system reliability, emissions reduction and overall system adequacy, including clean dispatchable capacity.
Government also intervenes as a balance‑sheet partner through the CEFC, particularly where assets are system‑essential but returns are marginal or difficult to isolate at the project level. Transmission infrastructure and large‑scale firming assets fall squarely into this category.
Jacob Elkhishin explains, “the only thing that’s really being said at a government level is subsidies for transmission distribution.” This reflects the reality that network‑level risk and long asset lives make transmission and firming infrastructure unbankable on purely commercial terms. CEFC’s concessional finance is therefore critical to enabling system‑essential investment at scale.
Grant‑based support plays a complementary role, particularly for first‑of‑a‑kind deployment and system integration. Public funding helps absorb early technical and coordination risk so that assets can become replicable and investable.
ARENA grants focus on:
- First-of-a-kind-deployments
- Hybrid projects
- Grid support technologies
- Battery manufacturing and supply chains
Finally, government intervention also occurs through mass‑market incentives such as grants for household solar and batteries. While politically popular, Craig Amos cautions that these measures “don’t necessarily create a more stable energy system overall,” as it is the industrial utility-scale side of the system that has the biggest impact. Their system value depends on coordination through mechanisms such as virtual power plants, again highlighting the importance of system‑level enablement.
Innovation and technology
Technology is a key enabler to achieving net zero emissions in the energy sector.
The challenge lies in the speed at which technologies can be deployed, integrated and scaled within an ageing and constrained energy system.
As Jacob Elkhishin notes, “from an energy perspective, the technology’s there… the key challenge is infrastructure and getting that infrastructure ready to handle this shift in how the grid is structured.”
Physical versus digital innovation.
Large‑scale physical innovations such as new battery chemistries or generation technologies require long development, testing and approval cycles. Mathavan Parameswaran explains, “if you’re talking about big technology like new types of solar or batteries, that obviously takes years to be ready.”
By contrast, digital and software‑based innovation can move more quickly. Mathavan Parameswaran highlights that “software technology that helps you manage electricity and how it interacts with renewables can be a bit quicker nowadays — especially with AI helping speed up the process.” These technologies can improve forecasting, routing and optimisation, helping to reduce system inefficiencies and operational risk.
However, digital optimisation cannot compensate for insufficient physical infrastructure. Renewable energy, storage and data‑driven optimisation must still move through the grid.
Data centres, AI and demand‑side pressure
Innovation also introduces new sources of demand.
Mathavan Parameswaran and Jacob Elkhishin both emphasise that AI and data centres will significantly increase electricity consumption. This does raise questions about whether current planning assumptions fully account for this growth.
While data centres increasingly commit to renewable supply, Mathavan Parameswaran adds that dispatchability and storage remain unresolved at scale.
Battery technology is improving, but as Jacob Elkhishin notes, “the technology is not there yet” to fully meet the high‑power, continuous demand of large data centres without broader system upgrades.
For him, the issue is not whether innovation will arrive, but “whether it’s going to get there within the timeline they’re projecting.”
Jacob Elkhishin
Battery technology is improving, but as Jacob Elkhishin notes, “the technology is not there yet” to fully meet the high‑power, continuous demand of large data centres without broader system upgrades.
Mathavan Parameswaran
Mathavan Parameswaran explains, “if you’re talking about big technology like new types of solar or batteries, that obviously takes years to be ready.”
How the energy market should prepare for net zero
Treat transmission and storage as first‑order investments, not enablers.
Treat transmission access and firming as core components of project viability from the outset, not downstream considerations. Alignment with system plans and early engagement on connection and commissioning risk are essential.
Use government mechanisms deliberately to manage unpriceable risk.
Proactively design projects around available public mechanisms as critical parts of the capital stack.
Deploy innovation to reduce system risk.
Innovation efforts should focus on forecasting, optimisation, grid visibility and coordination (e.g. AI‑enabled dispatch, virtual power plants).
Plan explicitly for rising demand from data centres and electrification.
Incorporate high‑growth demand sectors and stress‑test infrastructure against peak and extreme conditions. Failure to do so risks diminishing returns on renewable investment and undermines energy security.
Align timelines and budgets.
Align timelines and budgets honestly with physical and institutional constraints.
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