A broad range of stakeholders have provided feedback on the AEMC’s proposed approach to transmission access reform, which is being considered through our Coordination of generation and transmission investment (COGATI) review. 

In June 2019 the AEMC published a directions paper outlining further detail on the need for transmission access reform to enable the connection of new wind and solar across the national electricity market and deliver on the Integrated System Plan (ISP). The paper also set out the Commission’s proposed approach to changing the way generators access transmission networks. The proposed reforms aim to address both the need for greater certainty for generators that they can get their energy to consumers, and the need to reduce the financial and risk burden on consumers in funding new transmission investment.

The access reforms involve three inter-related aspects:

  • wholesale electricity price reform involving generators receiving  a dynamic regional price that more accurately represents the marginal cost of supplying electricity at their location in the network 
  • the introduction of transmission hedges as financial risk management options that generators can obtain and use to manage the risks of congestion on the network
  • transmission planning and operations being informed by generator purchases of transmission hedges to reduce the risk of consumers paying for incorrect transmission decisions.

We have received 36 submissions on the directions paper from a wide variety of stakeholders, including generators, network businesses, renewable energy companies, equity investors, market and industry bodies as well as large energy users and consumer groups. Stakeholder submissions are now available on the AEMC’s project page.

Key themes from stakeholder submissions included: 

  • Dynamic regional pricing could provide signals for efficient dispatch of generation and more efficient generator locational decisions. However, care should be taken to design the reform in such a way that it does not decrease liquidity in the contracts market or increase market power. 
  • Transmission hedges could increase certainty of access to transmission network capacity and reduce costs for consumers. However, generators want more information about how firm the products would be – this influences how much transmission hedges may reduce risk. 
  • A reform model with dynamic regional pricing and transmission hedges that does not directly link to the transmission planning framework would be preferable.
  • The COGATI review timetable is ambitious, and a lengthier period of consultation on the detail of reform may be required. Stakeholders noted the importance of the Commission providing additional market design details over the coming months.
  • The proposed July 2022 implementation date for the wholesale pricing, financial risk management and transmission planning reforms may be problematic. Stakeholders highlighted the time needed to develop and test these reforms before they are implemented, which may be challenging alongside other reforms such as five minute settlement. 
  • Some form of impact analysis on the intended reforms should be undertaken. 

Wholesale pricing reform

Stakeholders had mixed views on dynamic regional pricing, which involves putting a price on congestion and introducing a signal for generators that reflects their costs of using the transmission network. 

Transmission networks, large energy user groups and the market bodies supported the reform because dynamic regional pricing would provide signals to facilitate more efficient dispatch of generation in the short-term, and more efficient generator locational decisions in the long-term. 

The majority of generators and some investors opposed wholesale pricing reform. These stakeholders said there is insufficient evidence of the problems that dynamic regional pricing is intended to resolve, and that dynamic regional pricing would not provide long-term signals for investment. These parties also suggested that the effects of dynamic regional pricing on market liquidity and market power need to be considered further. 

Financial risk management

Most stakeholders were generally supportive of introducing transmission hedges, as they would be useful as a financial risk management tool to provide greater certainty of access to transmission network capacity. In addition, many stakeholders supported the idea of transmission hedges providing a source of funds that can be used to reduce the transmission use of system (TUOS) charges that consumers pay.

The majority of generators and some investors opposed the proposed transmission hedges, suggesting that the firmness of the hedges needs further detail. Depending on how firm the hedges are influences how much they would reduce risk for generators.

Transmission planning and operations reform

Stakeholders agreed with the Commission that it was important for transmission hedges to effectively interface with the transmission planning regime, including the Integrated System Plan that is currently being actioned. While stakeholders were open to the option of generator purchases of transmission hedges informing the Integrated System Plan, most stakeholders supported the Integrated System Plan being used as a guide to how many transmission hedges would be available for purchase.  

Renewable energy zones

In the directions paper, the Commission discussed facilitating renewable energy zones (REZs) as a transitional measure preceding transmission access reform. The Commission discussed two possible options for reform:

  • Allowing transmission network service providers (TNSPs) to assess approve connections from prospective generators over a period of time and in similar locations as a group. 
  • A model adapted from the Public Interest Advocacy Centre, which relates to sharing the costs of investment in a REZ between consumers, generators and TNSPs. TNSPs would recover the costs of building to a prescribed ‘efficient’ capacity level from generators and from consumers. They could also choose to provide additional capacity to generators on a speculative basis.

Stakeholders held mixed views on both options. Some TNSPs and most generators expressed concerns about the complicated commercial and legal arrangements that the first model could entail. However, consumer groups were generally supportive of this approach. The majority of TNSPs were opposed to the second model because of its complexity, while some investors, generators and consumer groups thought it had merit. 

Stakeholders also proposed alternative options for REZs, including the establishment of a REZ fund or transmission bonds to fund REZs. Some stakeholders also suggested that an approach to REZs be facilitated through a separate workstream as part of the broader COGATI process.  

Implementation process

Most stakeholders that favoured the proposed COGATI reforms supported the three aspects of the reforms being implemented simultaneously. A number of stakeholders also recommended that AEMO publish information relating to constraints and dynamic regional prices ahead of the COGATI reforms being implemented.

Next steps

There will be further opportunities for stakeholder input on transmission access arrangements throughout the COGATI review process, with a draft report currently scheduled for late September 2019.
We have formed a technical working group of experts from the market bodies, the Energy Security Board, TNSPs, generators and consumer groups to provide input into the proposed reforms and to help develop rule change requests needed to support the reforms. The technical working group will next be meeting on 5 September 2019.  Discussion notes from these meetings are published on the project page for the review after each meeting. 

Media: Prudence Anderson, Communication Director, 0404 821 935 or DL (02) 8296 7817.


BACKGROUND

This work is part of the AEMC’s broader package of changes to the regulatory framework to support new investment in transmission networks in line with AEMO’s Integrated System Plan.

Other key reforms in the package are:

  • streamlining the regulatory process for priority transmission projects – this is being progressed through rule change requests to the AEMC from the Energy Security Board
  • supporting the seamless integration of large-scale energy storage systems – this will be progressed through a rule change request from AEMO
  • embedding the Integrated System Plan in the regulatory framework through changes to the National Electricity Rules and National Electricity Law – this will be progressed by the Energy Security Board.

About the Integrated System Plan

AEMO’s Integrated System Plan, published in July 2018, sets out where and when network investment needs to happen to support the large amount of new generation connecting to the grid in the coming years. 

The COAG Energy Council asked the Energy Security Board to work with the market bodies - the AEMC, AEMO and Australian Energy Regulator - to make the Integrated System Plan “actionable”. 

The AEMC has developed a comprehensive reform package as part of that process. Our report on improving the coordination of investment in electricity generation and transmission, published in December 2018, sets out the nuts and bolts of how to deliver the Integrated System Plan. The report was developed in consultation with stakeholders and underpins the Energy Security Board’s vision for making the Integrated System Plan actionable.  

See also:
•    the AEMC’s System security and reliability program
•    Terms of reference from the COAG Energy Council.