The latest Gas Statement of Opportunities (GSOO) for eastern Australia indicates sufficient gas to meet demand provided LNG imports can commence by winter of 2023. This is when existing production from Longford in Victoria (which takes gas from several offshore fields) takes a nosedive. Even then shortages will emerge by around 2026 unless there is additional investment to either increase supply or to reshape the demand side. Pipeline investments are also likely to be required.
The potential shortages in 2023 if gas import is not up and running in time are only forecast for temporary demand spikes if there is a 1-in-20 cold winter. Conversely this is based on a supply forecast that includes some “anticipated” rather than committed new supply.
Figure 1: Anticipated supply/demand for eastern Australia to 2040
Source: AEMO, GSOO
In any case it is a bit of a head-scratcher that the world’s largest LNG exporter (for now) may also need to set up an import terminal in order to meet demand. The Port Kembla project seems to have won the race to be first against a handful of other potential projects in NSW and Victoria. One of the latter, AGL’s Crib Point project is looking unlikely after the Victorian environment minister recommended the project not go ahead due to the environmental risks to local wetlands and marine life. Given the Victorian government’s general antipathy to gas development, this recommendation is unlikely to be overturned. Victoria is more likely to implement demand reduction policies – AEMO modelled the impact of a moratorium on new residential gas connections, for example.
On the supply side, the AEMO projections appear broadly consistent with the conclusions from other exercises, such as the ACCC’s gas inquiry update and commercial forecasters EnergyQuest and Wood Mackenzie.
AEMO’s central demand scenario (below) looks remarkably stable over a twenty year period, with only demand from gas-fired generators fluctuating much. The fact that AEMO also models electricity supply and demand explains why this element of demand is more dynamic.
Figure 2: Gas consumption forecast by sector to 2040
Source: AEMO, GSOO
Even if one looks at the other scenarios, there’s not that much change, except potentially in the hydrogen scenario, where a material amount of gas demand is displaced due to hydrogen switching and blending into the gas distribution networks. This is a curious situation – we are in the midst of one of the great energy transitions, and we think demand for one specific energy vector is going to be pretty stable for two decades or more? It essentially signals that the demand side is something of a placeholder – no-one really knows, including AEMO, what the long-term future for gas is. They diplomatically note that since the federal government has not confirmed its suite of policies that are intended to driver the “gas-led recovery” they have not modelled the potential increase in demand that could result but will provide an update should that happen. Don’t hold your breath…
At a more granular level, one key change is that the changing electricity market dynamics will lead to the peak gas demand from gas-powered generation (GPG) will switch from summer to winter. This is due to increased renewables, which (solar at least) will by weighted towards summer and coal plants being squeezed out. But this means peak demand from generators is more likely to coincide with peak residential demand (for heating).
If there is a supply crunch, retail customers normally get priority over bulk users like industrials and GPG. But if GPG is only demanding the gas so it can keep the lights on (and power electrical heaters), then that could create a bit of a conundrum. That’s assuming the infrastructure (pipelines storage) can get the gas to the right place at the right time in these peak demand situations. Increasingly, more of the peak supply will need to flow south from Queensland, and at some point, that will exceed existing capacity of the pipelines that can do that.
AEMO emphasise that there is no single solution that can address all the future gas system needs, rather that “a suite of complementary investments in new gas fields, LNG import terminals, pipeline infrastructure and storage may provide the most efficient, reliable and secure outcomes for gas customers”. But gas producers and infrastructure providers are caught between the vagaries of government policy (which given net zero targets, may well lead to a big uptick in electrification, hydrogen switching or simply demand destruction) and global economic drivers (which could lead to gas price gyrations now Australia’s prices are firmly linked to international ones, and could independently lead to closures of large industrial users). Will they be confident enough in the future to commit to multi-decade investments that may be needed in a few years’ time, but run the risk of stranding shortly after?
This is not to say that we should expect a Texas style dramatic supply shortage of gas. Rather the supply crunch, if it comes, will be a slow burn…