Access reform in the NEM: a better way to coordinate investment


By AEMC executive general manager of security and reliability Suzanne Falvi, AEMC director Victoria Mollard and AEMC senior economist Tom Walker

The technology revolution has increased innovative generation capacity across the nation, with large-scale wind, solar and storage now well-established. Even more generation will be built in the national electricity market (NEM) in the coming years, taking the place of ageing coal-fired power. Getting the right generation and transmission investment in the right place at the right time is key to keeping costs down for consumers.

The Australian Energy Market Commission (AEMC) has proposed reforms to the way generators connect to and use the transmission network in the NEM, with potentially significant consequences to the way in which transmission and generation infrastructure is planned, invested in and paid for. If implemented, these reforms will be among the biggest changes to the electricity market’s design in 20 years. 

The AEMC proposes to move away from the current model of regional electricity pricing to introduce “dynamic regional pricing” for generators. Generators would eventually be able to purchase firm transmission rights, which provide them access to the price that consumers pay for electricity. Transmission companies would be compelled to provide transmission services consistent with the level of firm access paid for by generators.

Linking transmission capacity to access rights would extend the commercial drivers of generation investment to the transmission system. Doing so should promote more efficient investment in both generation and transmission.

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These reforms are a necessary complement to embedding the Australian Energy Market Operator’s (AEMO’s) Integrated System Plan (ISP) into the transmission businesses’ planning processes, and improvements to the existing cost-benefit analysis processes undertaken by the transmission businesses and the Australian Energy Regulator (AER).

The AEMC has been working closely with these other market bodies to ensure a coordinated approach to transmission policy development.

The current access regime in the NEM

Since the start of the NEM in 1998, generators have had a right to negotiate connections to the transmission network, but no right to be dispatched to the shared network.

Under the prevailing framework, a generator’s financial access to the region-wide price is intrinsically linked to its physical dispatch. Physical dispatch every five minutes is determined by complicated software which maximises value of trade, taking into account generators’ offers to sell electricity and, importantly in the context of this discussion, the physical capacity of the transmission network.

When there is congestion (also known as constraints) on the transmission system, generators that would otherwise be dispatched because their offer price to sell electricity is below the region-wide price are not dispatched. As they are not dispatched, they therefore do not receive access to the region-wide price.

Coordination of generation and transmission investment (CoGaTI) under current access regime

Under the current regime, no individual generator has preferential physical dispatch (and so access to the region-wide price), even if it underwrites a transmission asset’s construction. This creates a free-rider problem. Each individual generator would prefer for other generators to underwrite transmission investment, to avoid the cost of doing so while enjoying the benefits that the transmission infrastructure provides to all generators.

As a consequence of this free-rider problem, shared transmission asset investment decisions are the province of regional, transmission network businesses. Transmission businesses are subject to incentive-based economic regulation of their revenues for the provision of transmission services, as well as various other obligations relating to reliability, planning and investment decision-making processes.

In contrast, and consistent with a foundational principle of the NEM, decisions to invest in generation capacity are made by businesses operating in a competitive environment. The result is that risks associated with generation investment rest with those businesses and not consumers or taxpayers. Investment in generation assets is market-driven and takes account of expectations of future demand, the location of energy sources, access to land and water and access to transmission.

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Investment and operational decisions by generators and transmission businesses should work together to achieve overall efficient outcomes. Yet as a consequence of the current access regime, there is an inherent disconnect between market-based, decentralised generation investment decision-making and centralised, regulated transmission investment decision-making. This creates wide-ranging issues, and has been the source of no fewer than 13 reviews since the market started. Most prominent of these issues are:

  • limited intra-regional locational signals reflecting congestion: all generators which are dispatched receive the region-wide price. Consequently, there are only limited intra-regional price signals reflecting transmission congestion.
  • risk allocation for transmission investment: while there are regulatory processes in place designed to limit the risk of poor transmission investment decisions being made, end consumers are ultimately exposed to the risk of inefficiently located, sized or timed transmission investment.

As we face the future the benefits of addressing these issues are likely to be material. The market is undergoing a significant transformation, with an unprecedented level of new generators seeking to connect to the network. Proposed generation roughly equal to the current size of the NEM (50GW) is foreshadowed for connection to the grid over the next 10 years. This new generation is unlikely to be located close to plentiful existing transmission capacity. The market is shifting from highly concentrated areas of generation close to coal mines (e.g. Hunter Valley, Latrobe Valley) to more dispersed and smaller, modular generation spread more evenly through the network.

The AEMC’s proposed approach: CoGaTI implementation – Access

The link between a generator’s access to the region-wide price and its physical dispatch is so intrinsic to the market’s design that it is easy to forget it was a design choice: a choice that was made for good reasons during the original NEM development but that is neither inevitable nor irrevocable. Indeed, most electricity markets around the world do not link market access to physical dispatch in this way.

The AEMC proposes that where congestion arises and transmission constraints occur, pricing regions will be dynamically created which will reflect transmission constraints that are actually occurring at that particular time.

In any individual five-minute dispatch interval, dispatched generators would be paid the new, dynamic regional price that applies where they are connected, rather than the existing region-wide price. This breaks the link between a generator’s physical dispatch and its access to the market-wide price. Where there are no constraints on the transmission network, prices would be the same across the existing region, so generators would all receive the existing region-wide price. Consumers will continue to be settled at the existing region-wide price regardless of their location within the existing region.

A consequence of this change is to introduce a new risk to generators arising from generators not being settled at the price that consumers are paying. The AEMC is recommending a phased approach to managing this risk.

Initially, the AEMC is proposing that this risk should be addressed, in part, by providing financial compensation to generators on the difference between the regional reference price and the dynamic regional price of the generator. The money to back this compensation arises from the difference between the price market customers are being settled at (the existing regional price) and the price some generators are being settled at (the new, dynamically determined regional price of the generator). Financial compensation would be dynamically allocated to generators on the basis of their capacity.

Dynamic regions introduce a signal to generators that reflects the short-run costs of using the network. This would provide better information to generators about where congestion occurs, which they can consider when making their locational decisions. It also removes current incentives for generators’ disorderly bidding when there is congestion. The patterns and costs of congestion revealed by the dynamic location of regions should enable better transmission planning, which would still happen through centralised processes.

However, despite the benefits of the above changes, the AEMC is concerned that alone they will not result in optimal outcomes. While better information improves the likelihood of good transmission investment decision-making by transmission businesses, the planning of transmission remains a fundamentally centralised approach, disconnected from the market-led approach to generation planning. To address this concern, the AEMC proposes to subsequently introduce firm transmission rights. Generators would be able to buy firm transmission rights from a transmission business in return for either being physically dispatched or paid for the lost revenue from not being dispatched.  Transmission businesses would be compelled to provide transmission services consistent with the level of firm transmission rights procured by generators.

Because the transmission rights are a firm hedge between the dynamically determined regional price and the existing region-wide price, generators would receive the full benefit of the transmission upgrade they underwrite – avoiding the free-rider problem in the current access regime, and allowing greater reliance on commercial transmission investment rather than the existing, centralised and regulated processes.

Generators that do not hold firm rights would be exposed to more of the cost of congestion (because they have not contributed to alleviating congestion through the purchase of transmission rights), while generators that hold transmission rights would be hedged against the cost of congestion. This provides an incentive for generators to underwrite the appropriate amount, location and timing of transmission investment, balancing the costs of transmission investment against the costs of congestion, as well as other locational decision factors such as fuel resources. In effect, generators would be incentivised to contribute towards the cost of transmission, allowing them to factor this into their locational decision. Allowing generators to contribute funds towards transmission infrastructure would introduce more commercial drivers on transmission businesses and more commercial financing of transmission infrastructure.

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The approach would result in a closer alignment of generation and transmission investment with substantial benefits associated with better-aligned processes of generation and transmission investment, which can reduce costs to consumers. If, despite this better alignment, poor coordination does occur, then generators, rather than consumers, bear more of the risk and cost.

These changes have the potential to put downward pressure on prices for electricity consumers in the longer-term by minimising the total system cost of building and operating both generation and transmission over time.

Next steps

The AEMC recognises that these proposals are significant reforms. It is developing a work program to develop and consult on the proposed changes in its CoGaTI implementation – Access project, with the aim of implementing dynamic regional prices by mid-2022 and firm access rights by mid-2023. The AEMC will be working closely with all of the other market bodies, such as the ESB, AEMO and the AER to ensure a coordinated approach to transmission policy.