The end of open access What the future holds for transmission access reform in the NEM

What you need to know

• On 5 May 2022, the Energy Security Board (ESB) published its consultation paper on transmission access reform, a copy of which can be accessed here.
• The ESB has shortlisted four models for detailed design.
• Two of the models are based on market participants' investment timeframes (i.e. the time when investment decisions are made). These are:
  • the congestion zones with connection fees model; and
  • the transmission queue model.
• The other two models are based on market participants' operational timeframes (i.e. the real time operation of the power system). These are:
  • the CMM with universal rebates model; and
  • the congestion relief market model (CRM).
• The ESB is not progressing the renewable energy zone (REZ) adaptation of the congestion management model (CMM) as originally recommended in its Post-2025 Market Design Review. Instead, it will focus on developing a congestion zone/connection fee-based model.
• Following consultation, the ESB will release draft recommendations in September 2022 for the detailed design of its proposed hybrid access model that incorporates one investment timeframe model and one operational timeframe model. The draft recommendations will then undergo consultation until October 2022, before the ESB submits a proposed rule change request to Energy Ministers in December 2022.

What you need to do

• Interested parties can register for the ESB's webinar on the consultation paper on 26 May 2022, 2-4pm AEST, here.
• Interested parties can also make a submission to the ESB by 10 June 2022 in accordance with the consultation paper (here).

NEM open access

What does NEM open access currently mean for market participants?

The current open access regime allows generators to negotiate a connection to any part of the network at any time, subject to the network connection process with the relevant transmission network service provider (TNSP) and the Australian Energy Market Operator (AEMO). Generators fund only the cost of the assets required to connect to the grid and do not contribute to the cost of the shared transmission network. Generators receive no guarantees that the network will be capable of transporting their output to load centres.

At present, generators locate in parts of the network that are already at capacity provided they can achieve lower generator coefficients (i.e. the coefficient that reflects the impact a generator has on a constrained transmission line from a one MW change in output) than competitors. This is because the National Electricity Market Dispatch Engine (NEMDE) prioritises the dispatch of generators with lower coefficients, all else being equal, to minimise the amount of energy lost due to congestion. 

What are the consequences of NEM open access into the future?

The ESB notes that the current open access regime is causing the following to occur:

• market participants are connecting in locations where they are not contributing any new variable renewable energy (VRE) and are instead displacing existing VRE generation. This leads to higher system costs for consumers;
• the level of system risk faced by investors is increasing because there is a lack of certainty regarding congestion and curtailment. This leads to higher costs of capital for investors; 
• storage and demand-side resources are not being incentivised to reduce congestion, and conversely, storage operators are being rewarded for competing with, and displacing, VRE generation during periods of congestion;
• as market participants locate in poor locations from a system planning perspective (e.g. non-REZ areas) this leads to a larger transmission system to be built than is otherwise required; and
• more expensive combinations of resources are being dispatched to meet demand than is necessary.

Investment model 1: Congestion zones with connection fees 

The congestion zones with connection fees model segregates the transmission system into zones that reflect the level of available hosting capacity for new generation. These zones signal to developers and investors which parts of the network are available for further development, which parts are reaching capacity and which parts are full. 

How are connection fees levied on different market participants?

Under the model, new market entrants would be incentivised to locate in areas with lower congestion by being charged lower connection fees. Connection fees may also be scaled depending on a generator's output profile. Incumbents are not subject to the connection fees given they have already chosen their locations. Storage may be exempt from connection fees or rewarded for offering congestion relief. Connection fees that REZ projects pay for access rights may be treated as a substitute for a connection fee under the model.

How would the connection fees be set?

Whilst fees would be fixed at the time of connection, generators could negotiate how to pay the fees over the life of the asset. The connection fees would be determined by the regulatory framework (i.e. fees would be set by TNSPs and approved by the AER as part of their transmission charging methodology).

Investment model 2: Transmission queue model

The transmission queue model establishes a two-step queue allocation method that confers priority rights to incumbent generators and thereafter on a first come first served basis (i.e. if the network has spare capacity) or via an auction (i.e. if the network is over-subscribed). 

Key steps in the transmission queue model

First, AEMO would determine the available transmission capacity in the network by analysing historical data on thermal capacity, voltage and stability requirements.

Second, participants would submit expressions of interest (EOI) to connect to the grid. 

Third, depending on the demand for transmission capacity, a queue allocation mechanism would apply as follows:

• if EOIs are less than the transmission capacity of the network, priority rights would be granted to incumbents and thereafter to new market participants on a first come first served basis (if there is spare transmission capacity in the network).
• if EOIs are greater than the transmission capacity of the network, an auction would be held. Proponents would be assessed on their bid price and marginal loss factor and allocated a position in the queue based on the competitiveness of their bid. Where bidders are equally matched, a generator that connected to the grid earlier would receive priority dispatch.

New generators who are lower in the queue can improve their position by paying transmission charges or installing storage. If a generator is willing to fund investment to offset the additional congestion they cause, they would be given a queue number of “zero”.

Operational model 1: Congestion management model with universal rebates

The CMM with universal rebates introduces a single, combined-bid energy and congestion market.  When a constraint is non-binding, the current NEM open access regime applies.  When a constraint is binding, the CMM introduces a dual system of congestion charges and rebates for market participants in eligible locations.

The below diagram illustrates a simplified version of the CMM with universal rebates.

Source: ESB

How are congestion charges levied on market participants?

Market participants who generate in congested areas would be subject to a charge that reflects the marginal cost of congestion at their location. In response to the charge, generators would align their bidding to the true cost of generation in order to be dispatched by NEMDE, thereby reducing the cost of dispatch. By receiving the regional reference price (RRP) and paying a congestion charge, generators are, essentially, facing a locational marginal price (LMP). Given demand-side and two-way technologies can access lower prices relative to the RRP, they are rewarded for providing congestion relief in congested areas.

How will the rebates be allocated to market participants?

When congestion occurs, market participants (incumbents and new entrants, irrespective of whether they locate in a REZ) that are subject to the constraint would be eligible to receive a congestion rebate from a rebate pool to mitigate any exposure to LMP. The ESB is consulting with stakeholders regarding design choices for rebate allocation metrics, including applying the queue mechanism or using availability, contribution factors or inferred economic dispatch (i.e. assumed cost) as the metric. 

Operational model 2: Congestion relief market model

The CRM establishes an ancillary services market to relieve congestion in operational timeframes. This would enable market participants to trade “congestion relief” every five minutes based on an initial dispatch run. If a participant is dispatched and it does not make an offer to sell congestion relief, it would be paid the RRP for its dispatch quantity. The trading of congestion relief enables low-cost participants to be dispatched ahead of higher cost participants through a compensation process.

How would the CRM work in practice?

First, market participants’ (initial) dispatch of energy as per the status quo arrangements would determine the prospective buyers and sellers of congestion relief in the CRM as follows:

• sellers – generators (loads) that participate in a binding constraint and are initially dispatched (but are not consuming); and
• buyers – generators that participate in the binding constraint and are initially constrained off (fully or partially).

Second, buyers and sellers would bid or offer into a separate CRM for each binding constraint.

Third, the quantity of congestion relief being bid or offered would be adjusted by each participant’s contribution factor in the constraint.

Finally, the market clears, determining a clearing price and quantity of congestion relief traded.

If a participant sells congestion relief, the quantity of congestion relief is settled at the congestion relief price (not the RRP).

If a participant buys congestion relief, 

• the quantity of congestion relief is settled at the congestion relief price (i.e. the participant makes a payment); and
• the quantity of energy dispatched is settled at the RRP (i.e. the participant receives a payment).

Authors: Paul Curnow, Partner; Andre Dauwalder, Senior Associate; Joshua Hetzel, Lawyer; Miranda Aprile, Graduate; Sarah Gough, Seasonal Clerk.