Transmission slippage in the National Electricity Market (NEM) is a risk reallocation event – shifting cost, volatility and pricing pressure across generators, networks and consumers in real time.
For boards, investors and asset operators, the critical question in February 2026 is not whether transmission is delayed. It is: who is absorbing the financial consequences while projects wait?
Timelines and costs are moving
Major backbone projects are not landing on their original schedules.
For example, the Victoria to New South Wales Interconnector West (VNI West) is a proposed 500kV double-circuit transmission line connecting renewable energy zones in NSW and Victoria to improve grid reliability as coal plants retire.
The estimated total cost has blown out to approximately $7.6 billion, with projections suggesting it could rise as high as $11.4 billion. This represents a significant increase from previous estimates of around $3.6 billion to $3.9 billion, with the NSW section alone estimated at $3.7 billion.
Meanwhile, Transgrid is asking the regulator to pass roughly $1.1 billion of its cost blowout for its EnergyConnect transmission project on to consumers; confirming in February it had lodged an application with the Australian Energy Regulator (AER). CEO Brett Redman called the project “nation-critical” and said it would reduce household bills over time.
At a system level, price exposure from delayed build-out is now part of public debate.
Australian Energy Market Commission (AEMC) Chair Anna Collyer warned the Australian Associated Press in December last year that post-2030 price uplift risk emerges if renewable deployment slows as coal retires:
“The risk of prices rising after 2030 only emerges if we slow down renewable deployment just as coal plants retire,” Collyer said.
“This is a timing challenge, not a technology cost issue.”
The transition, in other words, has a sequencing problem – and transmission sits in the middle of it.
The Clean Energy Investor Group’s (CEIG) Transmission Bottleneck Analysis links delayed network build with rising congestion and renewable curtailment, noting impacts on project economics and increased reliance on thermal generation.
Curtailment – forced reduction in output because the network cannot accept energy – has a direct revenue hit against affected projects. There is potential for very high curtailment exposure under constrained conditions, according to Hamilton Locke citing Australian Energy Market Operator (AEMO) analysis.
This is where transmission delays stop being theoretical and become financial. So who ultimately pays? Consumers.
The AER has been explicit about cost incidence. In its Project EnergyConnect determination, AER Chair Clare Savage stated:
“It is consumers who ultimately pay for big energy infrastructure projects like this, so the AER’s job is to ensure that the project costs are efficient.”
That determination also outlined annual bill impacts across jurisdictions.
If costs rise or projects are delayed, recovery pathways matter – and so does regulatory oversight.
The CEIG report makes clear that congestion and curtailment undermine renewable project economics and create viability pressure.
In practical terms, capital is no longer pricing renewables generically; it is pricing locational constraint risk and sequencing risk. Projects that would otherwise clear on fundamentals can find themselves effectively stranded by transmission timing.
Regulatory certainty is critical to maintaining investor confidence while ensuring efficient cost recovery.
Dominic Adams, Chief Operating Officer of Energy Networks Australia, told Energy Insights:
"We are now seeing the delivery to commissioning of major new transmission projects, and it is critical that we can continue to deliver new transmission projects on time. Delays to new transmission infrastructure impacts the entry of new generation and impacts customer bills.
“The prudent and efficient costs to develop major new transmission projects are assessed and approved up front by the AER. Actual costs can still change throughout the delivery of a project, including costs outside the project developer's control.
It is important that the end-to-end regulatory process is allowed to run its course in a manner that ensures ongoing investor confidence and lowest cost long-term outcomes for customers.
This includes after the fact assessments by the AER to consider whether cost changes during project delivery represent prudent and efficient costs to deliver the new infrastructure.
“Customers should only pay efficient costs for critical new infrastructure. Effective AER oversight is critical to achieving these outcomes for energy customers, including ensuring a stable investment environment so that new infrastructure continues to be investable."
While coal declines and the renewable and storage build continues, transmission delivery remains contested.
The Clean Energy Council’s Chief Policy and Impact Officer William Churchill says it’s critical that renewables, storage and transmission are built “to schedule.”
The risk narrative for 2026 is therefore immediate:
Curtailment shifts revenue risk onto specific assets
Regulatory recovery pathways shift cost onto consumers
Sequencing gaps distort investment signals
Price volatility risk increases if timing misaligns
Transmission delays present asymmetric financial risk.
For senior leaders across the NEM, the strategic question is: “Which part of our portfolio is structurally short network capacity – and who is exposed?”