MELBOURNE (Reuters) – Australia is on the verge of becoming the biggest exporter of liquefied natural gas, with dozens of tankers a week carrying fuel to North Asia. It could also soon be importing LNG as supply sources in its southern states run out. Five LNG import projects are vying to start up between 2021 and 2022, possibly forcing gas users in New South Wales, South Australia, Tasmania and Victoria into more direct competition with Asian buyers for gas from northern Australia. Those states represent a yearly market of 420 petajoules (PJ), equivalent to 7.8 million tonnes of LNG worth about $3 billion. That represents just 2 percent of global LNG trade, but import proponents say the terminals would be another key outlet for spot cargoes of the fuel, especially during periods of low demand in the northern hemisphere.

Piping gas from Queensland in northern Australia to southern markets is expensive, making LNG imports potentially viable.

Credit Suisse analyst Saul Kavonic says, though, if final investment decisions are delayed into 2020, the case for imports will weaken as pipeline tariff reforms are likely by then.

“Based on the five proposals to date, Australia now appears to be planning to overbuild LNG import capacity in response to an overbuild of LNG export capacity,” Kavonic said. Eastern Australia has ample gas reserves to meet demand. The market outlook is tight, though, due to falling output from Exxon Mobil’s and BHP Group’s Gippsland Basin joint venture off Victoria, rising production costs and state restrictions on onshore drilling.

“We definitely would see a rationale for one terminal to give another source of gas into the east coast market,” said Nicholas Browne, Asia gas and LNG director at consultancy Wood Mackenzie. “We think one terminal would be sufficient till the mid to late 2020s.”

Import advocates need to be wary, however, of potential government moves to divert gas from exports to the domestic market and approvals for two long-delayed local gas projects, Narrabri and Surat. Gippsland Basin output could also prove more resilient than expected.

AGL’s Crib Point project is the most likely to go ahead, industry executives and analysts say. Australian Industrial Energy’s (AIE) Port Kembla terminal is also possible, but that hinges on signing up industrial customers. Two other projects – Newcastle LNG, led by privately owned South Korean firm EPIK, and Venice Energy, set up by former executives of BHP Group now at Integrated Global Partners – have yet to submit applications for state approvals.

Newcastle LNG and Venice Energy are looking to limit commercial risk by building import terminals and charging suppliers and traders to regasify LNG to sell to customers.

“We aim to provide a cost-efficient infrastructure solution in markets that are in need of gas,” said EPIK founder Jee Yoon.

Australian LNG producer Woodside Petroleum said gas for such pay-per-use terminals could come from Australia, the United States, Asia, wherever spot prices are cheapest.

“We would take those cargoes out of our portfolio, and we would decide where they come from,” Woodside Chief Executive Peter Coleman told reporters in February. Exxon Mobil is a big wild card, as it is considering imports to protect its turf in southeastern Australia, where it has been the dominant supplier for nearly 50 years.

Its infrastructure and experience selling into the southeastern market put it in a unique position, said Exxon Mobil Australia Chairman Richard Owen.

“We’ve got some competitive advantage and probably have a little bit more time than some of the other players,” Owen said at a business event on Friday.

ADVANTAGE TO AGL

Importing LNG into a gas-rich country is not new. Both Malaysia and Indonesia, the third and fifth-biggest LNG producers, have import terminals because transporting gas between islands by ship makes more sense than pipelines.

AGL, Australia’s No.2 energy retailer, is the furthest ahead with its import plan. Pending a state environmental review, it expects to make a final investment decision by early 2020, targeting first imports in 2021.

Its advantage over AIE is that it has an existing customer base for its gas.

AIE still hopes to be the first up and running, expecting approval from New South Wales this quarter for a mid-2020 start. “We think there’s a significant shortfall of gas in the domestic market,” said AIE Chief Executive James Baulderstone.

AIE, working with the world’s biggest LNG buyer, Japan’s JERA, and Marubeni Corp on import plans at Port Kembla in New South Wales, has been talking to industrial customers for more than a year, without yet signing any buyers.

“We’ve had oil prices moving around a fair bit and a lot of our LNG is priced to oil. That’s obviously a big issue,” Baulderstone said. At $60 a barrel for oil, several dollars below the current Brent price, AIE sees LNG imports as competitive with domestic pipeline gas. [O/R]

Industrial users are reluctant to commit to imports amid uncertainty over local gas developments, notably Narrabri in New South Wales, for which Santos Ltd hopes to win state approval this year.

Royal Dutch Shell’s and PetroChina’s Arrow Energy Surat project in Queensland, Australia’s biggest undeveloped coal seam gas resource, aims to start producing by 2021, but has been delayed due to a spat between the partners.

An international LNG trader said Australia could build up to two LNG import terminals, but called it absurd. The country just needs to lower pipeline tariffs to ease the flow of gas from north to south, he said.

“As a trader, I think it’s really insane. When this kind of insanity happens, it doesn’t last for very long.”

MAP: Australia’s proposed LNG import terminals tmsnrt.rs/2BKyDDJ

GRAPHIC: Eastern & south-eastern Australia domestic gas production (excluding LNG) tmsnrt.rs/2Lcqprj

MAP: Australia’s LNG projects and gas basins tmsnrt.rs/2MffKLY