AEMC releases latest Transmission Access Reform consultation

What you need to know

The Australian Energy Market Commission (AEMC)'s consultation paper provides further details of a hybrid model for transmission access reform consisting of: 

• a priority access mechanism, which prioritises financial access to regional reference price (RRP) (without prioritising physical dispatch), based on chronology of entry; and 
• a Congestion Relief Market (CRM), a new voluntary spot market which aims to achieve  lower cost dispatch by encouraging more cost reflective bidding behaviours than the current design. 

These reforms are part of a lengthy review of transmission access reform and congestion since 2018.  There are significant implications for existing and future generation and energy storage participants in the National Electricity Market (NEM). 

What you need to do

Interested stakeholders are invited to make a submission to the AEMC by 6 June 2024.

For more information on making a submission, refer to the Consultation Paper or get in touch.

Our observations

In our view there are significant issues associated with the proposals (some of which have been raised previously in the debate on transmission access reform):

Hedge markets

• The fundamental challenge of transmission access reform for the financial market is that it introduces basis risk.¹ The proposed hybrid model would introduce basis risk through the movement in the difference between the RRP and the local prices that would be faced by participants under the CRM.  This would challenge the ability of generators to sell hedge cover and increase the cost of hedge cover to retailers.  It has the potential to undermine generators' and retailers' incentives to hedge as their risks are no longer tied to the same price with retailers facing the RRP and generators facing local prices under the CRM or volume risk if they opt-out of the CRM. 
• The liquidity of the derivative market will be affected.  The types of products or their volume will be reduced, because of the changed risks and disparity in RRP outcomes.
• Reducing the volume of hedge contracts that units are able to sell is likely to complicate the business case for both investment in new controllable capacity and the continued operation of existing units.
  

Existing Power Purchase Agreements 

• We expect that the implementation of the CRM will be a change in law or a market disruption event under many existing Power Purchase Agreements (PPAs).
• We expect that this will result in opportunities for  parties to try to reopen the terms of the existing PPAs and for financiers to reconsider their position under their financing arrangements.  This has been a concern of all transmission access reform models, but the cost of this has not been considered in the AEMC consultation paper.

A further CRM model

It is surprising that participants are being asked to consider a further new CRM model given the number of processes that have been undertaken on transmission access since 2018.  It suggests that the issue will not be resolved in the near future and that it may ultimately be an out of date model as the market and government  programs deal with the congestion issue. 

No physical solution to congestion

• The AEMC consultation paper makes no suggestions as to whether Transmission Network Service Providers (TNSPs) can deal with connection applications in areas of congestion by not permitting connection to occur unless the connection applicant contributes to augmentation to avoid further cannibalisation of the position of existing connected generators and to avoid potential impact on the proposed Renewable Energy Zones (REZs).    
• This is a feature of the Designated Network Asset (DNA) framework (see schedule 5.12 of the National Electricity Rules), and has been incorporated into DNA access policies that have been accepted by the Australian Energy Regulator (AER). This is also similar to the NSW REZ access framework.
• It is unclear why this has not been addressed given that the AEMC recognises the key issue of congestion.

'Open access' arrangements – the case for reform 

Currently, the NEM has 'open access', meaning any generator that meets the relevant technical standards may negotiate a connection to any part of the network at any time, subject only to the network connection process with the relevant TNSP and input from the Australian Energy Market Operator (AEMO) on access standards and system strength. A generator may connect irrespective of whether the connection will provide value to, or cause congestion on, the broader power system. 

Connected generators can submit offers to sell energy into the market, which are dispatched at the volume determined by the NEM's central dispatch engine. The central dispatch engine determines the output of each generator that leads to the overall lowest cost dispatch to meet demand while maintaining system security and avoiding violations of the physical limits of the system, otherwise known as constraint equations. Generators receive the RRP for their energy dispatched every five minutes – if a generator is not dispatched, it gets no access and is not paid. 

The AEMC's paper attributes the following inefficiencies in the NEM to the linkage between access and physical dispatch: 

• "Increasing congestion risk: Current NEM arrangements mean the costs of congestion are often borne (at least in part) by pre-existing generators, rather than fully by a new entrant that causes the congestion. This can increase congestion and create a risk of “cannibalisation” (when a new generator locates in a congested area and displaces, or cannibalises, the dispatch of an existing generator). This means that investors may be exposed to unnecessary risk. 
• Investment inefficiencies: The regional pricing arrangements of the NEM mean that locational signals are not as clear as they could be for participants on where to build assets and best utilise the network. There could be stronger commercial drivers for investors to choose locations in order to minimise congestion. This means that REZ schemes may not deliver their expected benefits.
• Inefficient dispatch: When congestion occurs, the current wholesale pricing arrangements can create dispatch outcomes that do not minimise outcomes for customers over time. Flexible resources such as storage and demand response are also not encouraged to operate in a manner that recognises how they can add value to the system."

The AEMC has identified the following objectives for transmission access reform: 

1. Investment efficiency – improving long-term signals for market participants to locate in areas where they can provide the most benefit to consumers (taking into account the impact on overall congestion); 
2. Access risk – establishing a level playing field that balances investor risk with the continued promotion of new entry that contributes to efficient competition in the long-term interest of consumers;
3. Operational efficiency – incentivising cost reflective bidding to promote better use of the network in operational timeframes, resulting in more efficient dispatch outcomes and lower costs for consumers; and
4. Congestion relief – incentivising demand side and two-way technologies to locate where they are needed most and operate in ways that benefit the broader system.

The hybrid model  

The Energy Security Board (ESB's May 2023 consultation paper (see our previous article on this paper here) proposed a hybrid transmission access model, consisting of both: 

• the priority access mechanism, which prioritises financial access to RRP (without prioritising physical dispatch), based on chronology of entry; and 
• the CRM, a new voluntary spot market which aims to achieve a lower cost dispatch by encouraging more cost reflective bidding behaviours than the current design.

The hybrid model remains the AEMC's preferred option for transmission access reform. Particularly, the AEMC expects the hybrid model would: 

• improve locational signals for new investment; 
• address cannibalisation; 
• stimulate operational efficiency; and 
• incentivise scheduled storage and load to alleviate congestion.

The hybrid model was assessed against six alternative models as providing the greatest efficiency savings, reduced capex and fuel costs. 

Priority Access Mechanism

The priority access mechanism assigns generators a priority level in the energy market during operational timeframes.

The ESB had identified that the preferable approach to implementing prioritisation is by bid price floor adjustments, where participants with different dispatch priorities are assigned different bid price floors (BFPs) that set the maximum bid that they can make in the access dispatch run.

In 2023, a testing program was set up using AEMO's CRM prototyping to understand the impact of implementing priority access in the NEM dispatch engine (NEMDE). 

The testing demonstrated that soft prioritisation of generators may reduce cannibalisation outcomes compared to the status quo, without significantly increasing the RRP.

Implementing priority access 

The AEMC is seeking feedback on four priority access model options that may give effect to the bid price floor adjustment approach, and assign generators to a limited number of priority levels. These are: 

• Option 1: grouping by time-window (AEMC's preferred approach);
• Option 2: grouping by time window REZ model; 
• Option 3: two-tiers approach; and 
• Option 4: dynamic grouping algorithm (second AEMC preference).

Grouping by time-window 

This approach involves grouping generators by year for the duration of prioritisation, before rolling them up into a higher priority group as the number of available priority models is met. There are intended to be 10 levels of priority, with BFPs ranging from -$200/MWh for the lowest priority to -$1000/MWh for the highest priority. Within that range, the BFPs could follow a geometric sequence such that the level of firmness between adjacent dispatch priority is somewhat constant.

Source: Australian Energy Market Commission 

This model allows investors to have a good degree of certainty regarding their effective level of priority relative to incumbent generators and other generators seeking to access the same area of the network at the time of making a final investment decision.

Grouping by time-window REZ model

This model is a variation on the grouping by time-window approach. The REZ model operates as follows: 

• Non-REZ generators enter the queue as set out in the time window model.
• REZ generators automatically move to the front of the queue when they connect in a REZ and commence operation.

Limits would be implemented regarding what constitutes a REZ for the purpose of priority access.

Two-tier approach

The two-tier approach categorises generators into two categories. Legacy generators, committed generators and generators participating in REZ are grouped into a priority tier. Other new entrant generators are assigned a lower priority. Each category is mapped to a BFP.

The model has the option to implement a mechanism that enables other generators who are locating efficiently to be allocated into the priority group. Such assessment could be undertaken by government or by AEMO, based on modelling efficient hosting capacity in certain zones.

Dynamic grouping algorithm

The three previous model options are "static" in that they are based on rules applied in planning timescales. An alternative is a "dynamic grouping" algorithm which is run close to, but before, real-time and is based on expected generation and transmission conditions. The algorithm would run sequential dispatches to progressively prioritise or deprioritise generators based on when they connect and whether their dispatch would need to be constrained. 

"While AEMC considers that the grouping by time window option is the preferable priority access model, the Commission is seeking feedback as to whether stakeholders see merit in a dynamic grouping mechanism."

Priority access

The AEMC paper includes significant detail on design options for priority access and the CRM.  These need to be reviewed closely.  Below we have highlighted the AEMC's preferred position for each option.

Treatment of legacy generators

It is the AEMC's preference that the priority access model substantially grandfather legacy generators. Under this model legacy generators would be allocated the highest priority level. They also propose that once allocated priority, incumbent generators are treated the same as new generators. This preference is based on ensuring public policy decisions do not discourage future investors through the perception of increased regulatory risk.

Timing of allocation of priority access to non-REZ generators

Currently the AEMC plans to allocate a priority level late in the connections process, but  before the final investment decision so as to ensure only genuine projects with a high probability of proceeding get allocated priority access while still providing investment certainty.

Timing of allocation of priority access to REZ generators

One of the objectives of transmission access reform is that it supports and strengthens jurisdictional REZ schemes. Currently the AEMC plans to allocate a priority level in the early-mid stage of the REZ development process and want to ensure generators who choose to participate in a REZ are allocated a higher priority than they would otherwise receive by connecting outside a REZ.

Congestion relief market 

The second element to the proposed hybrid model is the CRM. Under the CRM, market participants can increase or decrease their dispatch.  The mechanism promotes cost-based bidding over market floor prices, yielding more efficient physical dispatch through lower costs.  

Design

The CRM heralds three key design changes:

• Bidding and offer process for market participants;
• Dispatch process; and
• Settlement

Given the voluntary nature of the CRM, market participants who elect not to opt into the mechanism will not experience any changes in this regard.  Their dispatch outcome, as established in access dispatch, would be strictly 'locked' for physical dispatch.  As a corollary, settlement continues to follow the RRP.

Energy revenue (Non-scheduled) = adjusted gross energy (AGE) x RRP

Conversely, CRM market participants submit two sets of bids: the first feeds into access dispatch and the second into physical dispatch.  AEMC considers that this model will lower the costs of dispatch.  Settlement will also change for CRM market participants.  

Energy Revenue (Semi/scheduled) = AGE × RRP + (PQ - AQ) × (CRMP – RRP)² 

Implementation - 2  models  to consider (including a  new model)

There are two potential CRM implementation approaches – two-stage dispatch and a co-optimised dispatch  proposed by the AEMC. 

Two staged 

Under the two-stage approach, dispatch runs one after the other, starting with access dispatch process and then physical dispatch (which is modified for those participating in the CRM).  This model generates two sets of RRPs and accordingly, two choices for settlement.  AEMC has expressed a preference for the access RRP which is calculated in priority access dispatch.  

Co-optimised

The AEMC recognised flaws in the 2 stage process, and is developing  a co-optimisation method.  In brief, access and physical dispatch occur simultaneously.  This minimises costs of dispatch costs and constraints, owing to its objective function.

The AEMC welcomes stakeholder views on these concerns.  

AEMC Recommendations

In November 2023 Energy Ministers agreed to progress the agreed transmission access reform and congestion management through further design work. The Energy Ministers will consider the AEMC recommendations before making a decision as to whether to implement the hybrid model.

If a decision to proceed with the hybrid model is made by Ministers, a detailed implementation phase including developing draft rules would occur with corresponding consultation periods for stakeholders.

Want to know more?

New priorities transmission access reform and the future of the National Electricity Market (17 May 2023)

 The end of open access What the future holds for transmission access reform in the NEM (19 May 2022)

Authors: Dale Gill, Partner; Alexandria Brown, Lawyer; Murray Rissik, Graduate; Ethan Low, Paralegal; Cameron Saliba, Seasonal Clerk; Lauren Gunther, Seasonal Clerk; Ruby Ioannou, Seasonal Clerk.

_{1. Basis risk is a form of pricing risk whereby the income for a counterparty is no longer based on the price of the commodity that is the subject of the trade.}