By Ben Potter
Australians struggle to comprehend how one of the world’s three largest gas exporters might need to import liquefied natural gas to plug a looming shortfall caused by falling East Coast production.
Failure is an orphan, and this is one of Australia’s greatest policy failures, says Andrew Richards, Chief Executive of the Energy Users Association of Australia (members include big manufacturers BlueScope Steel, Brickworks, Visy, Orica and GFG Alliance).
LNG is typically more costly than domestic gas because customers must pay for it be frozen, carried and thawed out. Aspiring importers hope a looming surge in exports from US and Qatar will keep prices reasonable.
If it doesn’t, they might not sign up enough customers to justify the investment, and domestic gas users will have to look elsewhere.
Amid vociferous opposition to new gas projects and increasingly frequent climate emergencies, there are no easy solutions.
According to the Australian Energy Market Operator's 2024 Gas Statement of Opportunities, the Eastern states and Northern Territory produce about 2000 petajoules of gas a year. Just under 1400 PJs are used to produce and export LNG, and about 500 PJs are consumed by homes, commercial and industrial customers, and power generators.
The surplus – estimated at 77-112 PJs this year by the Australian Competition and Consumer Commission – is available to meet demand spikes caused by extreme cold, wind and hydro droughts and increasingly frequent sudden coal outages.
Problem is, production is falling faster than consumption, led by Bass Strait. The upshot is the surplus available for emergencies will steadily erode, AEMO says, and from 2028 to 2032 an annual supply gap of about 50 PJs will emerge, widening to 100 PJs to 200 PJs from 2033.
Complicating the picture, these projections are just best guesses; if electrification of households, transport and commercial and industrial firms, or production of biomethane or green hydrogen exceeds or fall short, the supply gap could shrink or widen.
The market has just squeaked by after earlier warnings. But manufacturers such as Oceania Glass and Qenos – faced with $14-$15 a gigajoule or more – have gone to the wall. (A million GJs make one PJ).
MST Marquee analyst Saul Kavonic says warnings have been ignored and large energy users such as aluminium smelters may tire of being asked to power down to prevent residential blackouts as supply crises get more severe. “The redundancy has just been gnawed away,” he says.
Solutions
To Richards, the solution is obvious: force Queensland’s LNG producers to send more uncontracted gas to the southern states. Richards says it was a big mistake to license Queensland LNG exports without setting gas aside for the domestic market, which raised domestic gas prices, but they shouldn’t be made to tear up contracts. Uncontracted gas is different; Queensland exported an estimated 72 PJs of spot cargoes in 2024, alongside about 1300 PJs under contracts.
“We can't be in a situation where we're exporting spot cargos of LNG while domestic market is in such a shambolic state,” Richards says.
Still, spot gas alone won’t cover a widening shortfall.
LNG imports
LNG imports could make a bigger dent. Iron ore billionaire Andrew Forrest’s Squadron Energy, Viva, Vopak Victoria Energy and Venice Energy are planning to import a combined 600-plus PJs a year at Port Kembla, Geelong, Port Phillip Bay and Port Adelaide.
These would defer gas shortages until the early 2030s, but face hurdles. They must secure regasification units and sign up enough customers to justify the costs. The problem is the cost of the gas. The ACCC cites an Australian Energy Regulator draft ruling in its Gas Inquiry 2017-2030 report that end users in southern states will likely pay $2.38 - $2.67 (12 per cent to 14 per cent) more per GJ for imported gas than for Queensland gas delivered via pipeline (about $22/GJ vs $19-$19.83/GJ).
Squadron’s CEO Rob Wheals told The Australian Financial Review in January he thinks an expected surge in global LNG production will bring prices down, and our purchases in the northern summer will cement that advantage. Kavonic says Wheals is dreaming -- domestic prices adjust to falls in LNG prices, and customers could use Squadron as a stalking horse to get cheaper gas from Queensland. There's a reason why import terminals haven’t been able to sign up enough customers, he says.
Southern comfort
If the ACCC is correct, that’s more than twice the $9/GJ that Jane Norman, Chief Executive of Amplitude Energy (formerly Cooper Energy) reckons her company can produce gas for from proposed new fields her company is exploring in Victoria’s Otway basins in Bass Strait. AEMO says new “Southern” fields (in Victoria, NSW and South Australia) could add about 200 PJs to domestic supply, deferring the supply gap until the early 2030s.
Amplitude’s new Otway fields could be online by 2028 and deliver 90 terajoules each day into the market, about a fifth of the decline in Bass Strait production. “This is the lowest cost, lowest emission gas that can be supplied into Victoria,” Norman says.
These projects are considered contingent by AEMO. They face arduous approvals and require upgrades to onshore gas processing plants and pipelines to reach potential. Policy interventions also make investors wary.
Norman says the federal government could help by passing reforms to streamline NOPSEMA’s offshore processes and cut state government duplication. (The reforms were shelved in a deal with the Greens; policy expert Graeme Samuel said in 2020 Canberra had failed the environment and should delegate authority under new national standards to the states.
Paying the piper
Incremental pipeline upgrades underway – including to the constrained links from Queensland to the Southern states – could defer shortages to 2029. Larger upgrades would push them out further but these require larger south bound volumes to justify the cost of building them.
Such volumes could come from Queensland’s Taroom Trough, being explored by Shell and juniors Elixir Energy and Omega Oil & Gas, or Northern Territory’s vast Beetaloo. Taroom is exciting interest because of Shell; Kavonic says it potentially has a few trillion cubic feet, compared to Southern fields’ “few hundred bcf” and “we need tcfs”. (A tcf is about 1000 PJs).
These are distant prospects. “Getting Northern supply down south probably is the quickest thing to do -- outside of the Commonwealth or someone like that underwriting a big LNG import,” Richards says.
One problem: big pipeline upgrades need a 50 year life to repay the investment; fossil gas may not be around that long amid accelerating climate-related emergencies.
“Renewable gas” -- biomethane and green hydrogen – may help. About 30 PJs is expected by 2031, but more is uncertain. The lack of easy options could explain the chatter about federal underwriting of LNG imports.
Andrew Richards, Saul Kavonic and Jane Norman will be joined by representatives of some of junior projects mentioned here at the Australian Domestic Gas Outlook conference in Sydney (31 March-3 April). Learn more.
To access the detailed conference program, download the brochure here