AEMO’s Draft 2022 Integrated System Plan
Fast Facts
On 10 December 2021, AEMO published the Draft 2022 Integrated System Plan (ISP). Submissions are due to close on 11 February 2022, in preparation for publication of the final ISP in June 2022.
Key points of note are:
AEMO has nominated its ‘Step Change’ scenario as the most likely scenario. This scenario envisages a rapid consumer-led transformation of the energy sector, and co-ordinated economy-wide action on emissions reduction;
AEMO forecasts a nine-fold increase in utility-scale variable renewable energy capacity is required by 2050, along with a five-fold increase in distributed PV in order to meet the predicted exit of coal generation;
AEMO expects coal generation to exit two to three times faster than anticipated in its 2020 ISP, with most brown and black coal generation to be withdrawn by 2032. This will require firming capacity to be trebled by 2050, supported by efficient network investment that makes this capacity ready and available;
AEMO forecasts delivered electricity to double, and reach around 330 TWh per year by 2050, to support the growing electrification of transport; and
AEMO forecasts that transmission projects will deliver $29 billion in net market benefits, from almost 10,000km of proposed new transmission projects.
For TNSP’s, the selection of Step Change alters the economics of future investment, by virtue of the interplay between the ISP and the Regulatory Investment Test for Transmission (RIT-T). This will place increased attention on the AEMC’s Transmission Planning and Investment Review currently underway.
For Generators, the choice of Step Change legitimises what has already been broadly understood; that without capacity mechanisms, it will be increasingly difficult for coal-fired incumbents to reach the end of their technical plant life as renewables and DER penetrate the system.
For DNSPs, this ISP provides a whole-of-system validation of their need to invest significantly in the low voltage network over successive regulatory control periods to expand network hosting capacity.
The ISP has become, over the past three years, the closest thing that the Australian energy industry has to a scenario-based blueprint of the impacts of net zero commitments and changing technology on existing generation. While it has been commonplace for industry participants during 2021 to select Step Change as their most likely scenario, the ISP now entrenches this and makes clear we are within the greatest period of change in the history of the Australian energy market.
For those companies that have not considered a fast-paced scenario as their most likely scenario (or have not undertaken scenario analysis) now is the time to update or undertake new scenario analysis, and importantly to understand the impacts, for business strategy, planning and decision-making purposes.
Key Themes
On 10 December 2021, AEMO published the Draft 2022 ISP. Submissions are due to close on 11 February 2022, in preparation for the final report in early 2022. Like the previous ISP, this update has undergone an extensive consultation process, with more than 120 written submissions being received by AEMO during the last 12 months and 25 stakeholder events hosted.
Most likely scenario
A key theme of this 2022 ISP is the change in the most likely scenario from which AEMO identifies the optimal development path. AEMO’s shift away from its central scenario in the 2020 ISP as the most likely scenario, and adoption of Step Change is significant. This was heavily supported by stakeholder consultation, where two-thirds of stakeholders nominated either the Step Change or the faster transition of the Hydrogen Superpower scenario as most likely.
The broader outlook of the Step Change scenario is a consistent, fast-paced transition away from fossil fuel use into renewable sources of energy, supported by increased digitisation that will focus on both demand management and grid flexibility, with efficiency being equally as important as electrification. AEMO sees domestic hydrogen production being used to support the transport sector, and as a blended pipeline gas. (We have commented on the economics and outlook for blended hydrogen within gas pipelines in a separate RP Insights article.) Significantly, the choice of the Step Change scenario brings, for the first time, a planning outlook to the NEM which accords with the Paris Commitment to limit global temperature increases to under 2 degrees.
Rate of change
A key takeaway from the 2022 Draft ISP is AEMO’s predicted retirement of coal generation at a rate that is much faster than has been predicted previously. AEMO’s latest modelling suggests 14 GW of the current 23 GW of coal capacity will likely be retired by 2030 in the face of price competition from increased renewables uptake, and operating challenges associated with aging plant. It is anticipated that all coal generation will feasibly exit by 2040.
These are transformative changes – wind generation in 2040-41 is forecast to nearly double compared to the 2020 ISP, and rooftop PV forecast at 150% higher with small-scale storage some 18 times higher than projected in the 2020 ISP. Further, AEMO forecasts that renewables will be providing 79% of total generation by 2030, 96% by 2040, and 97% by 2050 with:
DER representing 30% of renewable capacity, increasing from 15 GW capacity currently to nearly 69 GW by 2050; and
Grid-scale variable renewable energy (substantially provided through the REZ schemes) representing 70% of the overall renewable capacity, reaching 140 GW of capacity by 2050 and ensuring low-cost supply for consumers.
AEMO also forecasts significant investment and infrastructure development, to ensure dispatchable capacity is able to respond to dispatch signals and firm renewable generation. To ensure system strength and reliability, AEMO forecasts that the NEM will require:
45 GW of new development across batteries and hydro storage;
9 GW of gas-fired generation for firming during peak loads, especially during periods of fluctuating weather where renewables do not operate to the desired capacity, and to accommodate changing energy uses (i.e., EV charging); and
A focus on increasing the value of WDR to take advantage of any oversupplies.
Optimal development path
A major focus, and one of the key outputs of the ISP, is the implementation of the Optimal Development Path (ODP) for the NEM by setting out the development opportunities that provide the greatest benefits to the market into the near future, and classifying “Actionable ISP Projects”, which can be subject to a streamlined regulatory investment test (RIT-T) process. The investments outlined in the ODP are summarised below.
Table 1: Optimal Development Path Transmission Projects
Our Insights
Implications for Generation
The ISP modelling is primarily focused on the investments needed to ensure energy adequacy. While the modelling includes some analysis of power system security needs (particularly system strength and inertia) and describes the continuing role for gas-powered generation to provide system services, the Draft ISP assumes that these needs will be met in accordance with recent rule changes (e.g., the ‘Efficient management of system strength on the power system’ rule change), future changes such as those that may emerge from the Energy Security Board’s (ESB’s) Post-2025 reform recommendations, or technical changes that will be delivered through AEMO’s Engineering Framework. No additional gas-fired capacity appears to have been scheduled in the modelling specifically for system security needs.
These are significant assumptions, particularly given the scale and complexity of the reforms, their inter-relationships with each-other, and the stakeholders involved in their design and introduction.
A key consideration is how the ESB’s reform timelines for the mooted capacity and network congestion mechanisms relate to the investment requirements for generation and storage assumed by AEMO under the Step Change scenario. For example, in FY22 and FY23 alone, the ESB’s Post 2025 market design assumes reforms in:
Enhanced MTPASA Information;
Participation and Registry Systems;
Strategic investments in retail, wholesale and market systems;
Data interfaces, storage and management;
Integration and automation of registers and core systems;
Forecasting and operational system upgrades; and
Fast Frequency Response.
From FY24 onwards, the ESB assumes reforms including the capacity mechanism, the congestion management model, demand/DER scheduling, and greater DER integration.
The stated goal of a capacity mechanism is to support timely investment of the firm and flexible resources needed to maintain reliability in the face of a wave of plant retirements and increasing penetration of variable renewable energy (VRE). In doing so, it is anticipated that the mechanism would also provide confidence to governments that reliability goals will be met, ameliorating the need for government interventions. The potential timeline to implement such a mechanism is as follows:
Final advice on the detailed design of a capacity mechanism is due to be provided to Energy Ministers by the end of 2022. Following review and endorsement, the development of rule and regulatory changes may commence in earnest from mid-2023; and
Rule drafting, consultation and enactment would be likely to extend to at least the end of 2024, but most likely the first half of 2025 (by way of comparison, the Actionable ISP rules were finalised in March 2020, following COAG Energy Council agreement in December 2018).
It would be reasonable to assume that the first delivery period of a mechanism may not start until approximately four years after the enactment of regulatory changes (‘delivery period’ refers to the period in which the capacity rights and obligations apply, with one year delivery periods being used in many capacity mechanisms and markets in other jurisdictions). It is also worth noting that:
A capacity mechanism would require AEMO to undertake a large implementation and readiness program with industry;
Capacity mechanisms typically involve processes that start two to three years ahead of a delivery cycle, so that new resources can secure capacity certificates before construction (potentially as a precursor to a final investment decision);
There may be potential to shorten this timeframe through staging of implementation and by conducting processes in parallel; and
The first delivery period for a capacity mechanism is more than likely to be around 2029.
The timing for the implementation of the congestion management model is less clear, though likely to be faster than a capacity mechanism. A drafted rule change is scheduled for presentation to Energy Ministers by the end of 2022. Following that, a useful comparison would be the Five-Minute Settlement changes, which took four years from a final rule decision (November 2017) to commencement (October 2021).
The Step Change scenario outputs suggest that 3.4 GW of dispatchable capacity – gas, hydro and storage, excluding Snowy 2.0 – will be needed between 2023-24 and 2029-30 to complement new VRE investments and fill the gap left from coal retirements. It is therefore reasonable to assume that AEMO expects investment to follow the announcements, but not the detailed design or introduction of a future capacity mechanism or congestion management model. This assumes financial comfort on key design aspects will have been achieved, which may be an ambitious assumption.
Implications for Transmission
There have been some significant changes to the transmission build outlined in the optimal development path of the Draft 2022 ISP from the previous 2020 ISP as illustrated in Table 2. Changes to the ODP have real world implications for generators, investors, and networks as actionable transmission development in the ISP flows through to RIT-T obligations on networks, and (potential) project development.
Table 2: Optimal Development Path network investments – 2020 ISP v Draft 2022 ISP
^ Subject to decision rules
Major changes from the previous ISP are to the timing of the:
Sydney Ring transmission project;
the New England REZ Transmission Link;
Marinus Link; and
VNI West.
For prospective transmission investors, these changes are generally positive in terms of additional network capacity – for example, the bring forward of the Sydney Ring Northern loop between Bayswater and Eraring is expected to realise an additional 1500MW of network capacity; AEMO expects an initial 3000MW of network capacity to be released by development of the New England REZ; and the acceleration of Marinus Link will bring forward the expected development of over 2500MW of wind generation in Tasmania.
The changed arrangements for VNI West in the Draft 2022 ISP ODP are double-edged – on one hand AEMO has provided more certainty by selecting the KerangLink option as the only option for VNI West (securing a route pathway with REZ potential) but has pushed final project delivery out to 2031 from the former potential 2027-28 date, delaying potential development of the Victorian Central North REZ, and Murray River REZ.
All market participants should take note of the two key regulatory drivers behind project timings in the ISP – panel opinion on scenario likelihood; and state government policy settings.
Firstly, the inclusion of the Sydney Ring transmission project, and changed timing for VNI West are driven by the different scenarios used for the 2022 ISP, and the relative weightings of those scenarios. AEMO uses scenario likelihood weightings to rank candidate development paths under its least-worst regrets decision approach that forms the basis of the ODP. The strong consensus of panel stakeholder opinion on the Step Change scenario (50% of the panel considered this the most likely scenario) means that transmission build requirements are heavily influenced by the assumptions and inputs underpinning Step Change. This consensus-based approach to setting scenario weightings underlines the importance of early and continued engagement with the ISP development process by interested parties.
The other primary driver of these changes are state government legislative commitments. It is a requirement for AEMO to integrate into ISP modelling state policies that are, in short, legally binding. This provides states with a convenient mechanism to bring about changes to the ODP regardless of a project’s relative economic benefits. Notably, the expected timings of Marinus Link in the ISP has proven that even where a state policy (in this case the TRET) does not lay out the particular mechanism by which policy targets will be met, it will still carry influence over the modelling process, and allow projects to move through the ISP / RIT-T process. States are likely to make further legislative changes to influence transmission investment through the ISP process, as they compete to attract associated generation investment and broader economic benefits.
Implications for Distribution Network Service Providers
The Step Change scenario has profound implications for DNSPs, particularly those in NSW, Tasmania and Queensland which are in the early to mid-stages of their revenue reset processes. AEMO forecasts that DER will account for around 30% of renewable capacity, increasing from 15 GW capacity currently to nearly 69 GW by 2050. DER, by its nature, occurs on low voltage networks which are the least visible, least planned parts of the network. DNSPs are already witnessing this rapid uptake.
We are in a quickening of DER obligations on DNSPs. On 12 August 2021, the AEMC made a final rule determination to more efficiently integrate DER into the grid through new access, pricing and incentive arrangements [1]. Key features of the final rule relevant to DNSPs include that:
As part of the overview paper for its regulatory proposal, a DNSP will need to explain its proposed approach to export-related planning and investment against alternative options; outline how DER integration is managed through its regulatory proposal (i.e., connection services, pricing, expenditure) and discuss how its proposal is appropriate to meet expected consumer outcomes;
Export pricing will be optional for DNSPs. A proposal to implement export pricing would need to be part of the regulatory determination proposal and require the AER’s approval. Export prices will not apply to existing DER customers until 1 July 2025, unless the customer or retailer elects to be placed on the tariff;
DNSPs must include a basic export level that allows retail customers to export to the grid without charge to a ‘basic level’ for the DNSP’s two upcoming regulatory control periods (10 years); and
A DNSP must include an export tariff transition strategy as part of its tariff structure statement that forms part of its regulatory proposal to the AER. This must be included even if the DNSP does not propose to introduce export tariffs in the short-term, as DNSPs must be transparent about their long-term intentions;
The AER is required to review the current incentive arrangements to provide incentives for DNSPs to provide efficient levels of export services. If not considered and addressed, the existing arrangements could have the effect of incentivising DNSPs to reduce DER expenditure through the application of schemes such as the CESS and EBSS. The review should consider extending STPIS performance targets and incentives to export services;
The AER is also preparing a range of guidelines, including Export Tariff Guidelines, outlining the expectations of DNSPs in developing optional export tariffs and preparing their Tariff Structure Statement (TSS) proposals; and
A requirement for DNSPs to provide information and report on various metrics relating to export service performance in their Distribution Annual Planning Reports; and for the AER to produce annual DER network service provider performance reports, commencing in 2023.
The selection of Step Change creates a convergence of AEMO’s most likely scenario with the AER’s obligations to set prudent and efficient capital and operating expenditure allowances for DER related expenditure. Put simply, Step Change sets the blueprint for overall demand for new devices. For those companies that have not considered a fast-paced scenario as their most likely scenario (or have not undertaken scenario analysis) now is the time to update or undertake new scenario analysis, and importantly to understand the impacts, for strategy, planning and decision-making purposes.
For more information, contact Matt Rennie at mrennie@renniepartners.com.au
[1] AEMC, Rule Determination – Access, pricing and incentive arrangements for DER, 12 August 2021
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