AEMO urged to consider gas supply chains

The 2024 Draft Integrated Systems Plan continues Australian Energy Market Operator’s history of unrealistic gas supply chain and utilisation modelling. According to APGA National Policy Manager Jordan McCollum, simultaneous consultation on CSIRO’s 2024 GenCost report shows that it’s not entirely AEMO’s fault.

The biennial Draft Integrated Systems Plan (ISP) cycle delivers upon the Australian Energy Market Operator’s (AEMO) legislated obligation to plan for no-regrets investments in electricity transmission infrastructure. To do so, AEMO creates scenarios to stress test a model of the transmission grid, helping to identify investments necessary under as many scenarios as possible.

Despite this purpose, the scenarios created by AEMO are being more and more frequently considered predictions of the future of Australia’s energy system. This means that ISP scenario projections have a very real impact on investment choices in the Australian energy market.

For both this reason and the ISP’s intended purpose, it is important that AEMO get it right when forming these projections. Unfortunately, when it comes to gas, they rarely do.

An example of why this is the case can be seen in gas power generation (GPG) projections. GPG should be the simplest gas sector aspect for the ISP to get right. But each ISP continues to project GPG reducing within one to three years of publication before increasing after around a decade.

Conversations with AEMO and associated stakeholders indicates that this has, historically, been at least in part due to the ISP not considering failure cases beyond a single generator failing at one time – the opposite of what was seen during the 2022 energy crisis.

It has also been suggested however that projected low GPG demand over the medium term is also due to assumed government funding for utility scale batteries (such as the Federal Capacity Investment Scheme which includes batteries but excludes GPG), making batteries cheaper than GPG in the immediate term.

This, combined with increased GPG demand beyond the 10-year horizon, implies that GPG will regain its cost competitiveness when battery energy storage subsidies cease. But if this is the case then policy makers should be asking themselves whether they should subsidise utility scale batteries at all.

Suppressing near term GPG demand also introduces risk in GPG capacity investment. Battery subsidies won’t be around forever, and the ISP shows that when they stop GPG will be needed once more. But it is not reasonable to expect investors to maintain investment in GPG capacity with close to little expectation of near-term demand (or revenue) for the greater long-term good.

Either AEMO projections of GPG use do not reflect electricity market reality, or utility scale battery subsidies represent a risk to securing investment in the GPG capacity required to firm the variable renewable generation heavy electricity market of the 2040s.

Whether accurately modelled or not, the weight given to AEMO scenarios means that GPG investors will be seriously considering their market position. Without some form of revenue assurance during the 2025–2035 horizon, we may very well see GPG retract from the market at the very point when new capacity needs to be developed.

Looking beyond GPG itself, the dispatchable generation nexus between GPG and deep electricity storage shows where AEMO is missing an important part of the story. AEMO receives most of its ISP cost assumptions from the CSIRO GenCost series of reports. However, GenCost doesn’t project natural and renewable gas transmission and storage costs. This means that AEMO isn’t in the position to model these energy storage options.

AEMO is aware of what it is missing however, having referenced the capacity of the Iona Underground Gas Storage Facility in response to the Victorian Gas Substation Roadmap consultation. Iona alone has three times the energy storage capacity identified in the ISP as required new storage investment.

Without considering even existing natural and renewable gas storage and infrastructure options, AEMO may be overestimating the required investment in electricity storage options. This becomes especially concerning noting that AEMO’s largest projected category of storage investment is in the form of consumer energy resources (CER) i.e. customer purchased energy storage.

This is all without considering assumed progress of electrification of residential and commercial gas demand, which industry modelling shows is in no way connected to real world energy and appliance cost statistics.

There is hope for a better future however, where AEMO ISP scenarios and other projections genuinely consider the opportunities of gas supply chains and the impacts on gas customers.

The Federal Government commenced consultation into a “supercharged” ISP in 2023, exploring the opportunity to model electricity and gas supply chains side by side through multi-vector energy modelling. This could inject natural and renewable gas supply chain and storage economics into AEMO’s calculations, and ultimately reduce projected energy costs for all energy customers.

However, initial signs aren’t promising. The Federal Department initially dismissed multi-vector energy modelling as ‘impossible’ due to resourcing, despite the University of Melbourne having accomplished exactly this through a Future Fuels CRC Project. Impossible without increased investment in modelling capability, sure, but not impossible.

Every two years AEMO updates its ISP, and APGA provides advice demonstrating AEMO’s approach to gas supply chain fails to reflect market realities. Maybe development of a ‘supercharged ISP’ will help get things right, only time will tell.

This article featured in the March edition of The Australian Pipeliner. 

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