The single biggest driver of consumer prices in the past few years has been infrastructure spending on generation, poles and wires. Our Coordination of generation and transmission investment project is all about avoiding unnecessary costs being imposed on consumers through poor planning.

We are working with the Energy Security Board, AEMO and the AER to develop a framework to underpin an orderly power system transition under a range of future scenarios as described in the market operator’s integrated system plan within the ISP timeframe.

Public forum on changes to transmission access and charging

On 8 July 2019 the AEMC held a public forum to discuss the reforms needed to deliver new generation and transmission to underpin our future power system.

The power system, once made up of a small number of large, centrally located generators, is now made up of a large number of smaller, more dispersed generators. Such significant change to the shape of the power system means the way transmission and generation are planned and paid for must also change. 

The AEMC has proposed reforms to the way generators access and pay for transmission infrastructure. The proposed reforms would: 

  • give new connecting generators more certainty around getting their energy into the grid and delivered to consumers
  • reduce the costs and risks for consumers when it comes to building and funding new transmission infrastructure. 

The case for reform

The AEMC’s public forum – focused on proposals set out in a directions paper published in July 2019 as part of our Coordination of generation and transmission – access and charging review – was well attended by representatives from across the energy sector including market participants, consumer groups, investor bodies and market and regulatory institutions. 

Commissioner Charles Popple opened the forum with an overview of why the Commission thinks reform is needed now: so we can transition to a new and lower emissions power system in the most cost effective way for consumers without imposing delays. 

Stakeholders were able to ask questions of the Commission about proposed reforms to:

  • reflect the specific costs of supplying electricity  from different locations by introducing dynamic regional pricing
  • enable generators to manage price risks and secure access to the network through a transmission hedge. This will also improve investment certainty
  • guide new investment in transmission infrastructure so it meets the needs of consumers and the power system 

The view provided by the vast majority of stakeholders at the forum was that reform is needed and that we need to start somewhere – even if the reforms are complex. Key points raised by stakeholders include that the Commission should:

  • place a large weight on simplicity 
  • focus on promoting contract market liquidity 
  • design transmission hedges that are fit for purpose no matter what type of generation technology you have 
  • articulate a clear plan for transition and implementation to provide clear guidance for the market 

New Zealand experience

The New Zealand energy market, which has a similar market design to the NEM, but includes nodal pricing as well as firm transmission rights, offers some useful insights. 

James Flexman from Mercury Energy presented on the New Zealand’s journey in relation to transmission access frameworks.  Stakeholders welcomed the opportunity to hear the generator experience from another jurisdiction, and thought that this provided a number of learnings for the Australian context. Most notably, participants noted that dynamic regional pricing and transmission hedges should be implemented at the same time in order to make sure generators can best manage risks. 

Designing transmission hedges

In the afternoon section, stakeholders brainstormed options for the design of transmission hedges.  Market participants and finance institutions offered valuable insight on the types of access products that would help them manage risk and access finance. Government and regulatory bodies offered their experience in how regulatory frameworks can be designed to deliver desired outcomes. 

For example, it was noted that transmission hedges would be most useful if they could:

  • be offered for a range of durations (say, 3 years to 20 years)
  • align with the different generation technology types (e.g. a solar peak product); 
  • be purchased both within a region and between regions. 

A copy of the slides used at the forum can be found here 

The Commission is seeking stakeholder views on the issues raised in the directions paper and during the public forum. Submissions on the directions paper are due by 2 August 2019.

Stakeholder views will help inform the COGATI draft report, which will be published in September 2019.

Media: Prudence Anderson, 0404 821 935 or (02) 8296 7817


In the NEM today, generator investment decisions are made by private entities that are paid for the energy they generate once it is sold into the grid. If generators can’t dispatch or sell their energy they are not paid. The risk of investment in generation is therefore borne by the private sector. 

Transmission investment decisions on the other hand are made by regulated network businesses (publicly or privately owned). The network business does a cost/benefit analysis for each new investment and, if the benefits to consumers outweigh the costs of the investment, the regulator determines how much revenue can be collected from consumers to pay for the asset. The risk of transmission network investment decisions are therefore borne by consumers.

If there is too much congestion on the transmission network generators can’t sell their energy and are therefore not paid, and consumers pay higher wholesale prices as more costly generators are dispatched instead. If too much transmission is built, consumers pay for assets that are not required. 

A lack of coordination between generation and transmission investment decisions can mean that consumers pay more than necessary.

The AEMCs proposed reforms to transmission access and charging are designed to remove this disconnect, by exposing generators to the local marginal price through dynamic regional pricing, and giving generators the ability to purchase transmission hedges to manage price risks that may arise under congestion.  Transmission hedges would inform transmission planning decisions, and offset transmission use of system charges. This means that the TUOS component of a customer’s bill should decrease, potentially significantly.