As Australia gets set to overtake Qatar as the world’s largest exporter of liquefied natural gas (LNG), it is also looking to import the commodity as its southern states face a looming supply crisis.
According to new modelling by independent consultancy EnergyQuest, gas production in New South Wales, Victoria, Tasmania and South Australia will start to fall short of demand by 2022.
But rather than pumping gas from the large resources in the north of Australia, the states are instead looking at five projects to import LNG from overseas.
These projects include AGL Energy’s (ASX: AGL) proposed floating storage and regasification unit (FSRU) at Crib Point near Melbourne and private company Venice Energy’s planned three-stage LNG project at Port Adelaide, which starts with an FSRU followed by a power station.
A consortium made up of Twiggy’s Squadron Energy, Marubeni Corporation and Japan’s Jera Co Inc (the world’s largest LNG buyer) are determined to build an LNG import facility at Port Kembla near Wollongong, NSW, while oil and gas supermajor ExxonMobil is considering an LNG import facility in Victoria.
In addition, South Korean developer EPIK has proposed an FSRU for Newcastle, NSW.
While it may seem ironic to import gas when we already have the resources in the country, there are many reasons why these projects could be viable options to secure future supply for the east coast.
Gas production from Victoria’s Gippsland fields is rapidly declining and while the state is known to have abundant onshore resources, government legislation has imposed bans on exploration and development, including fracking.
This leaves a large gap between supply and demand.
According to EnergyQuest’s recent 130-page report East Coast Gas Outlook to 2036, the southern states will require gas from the north to meet local shortfall as early as 2022.
During the transition period, around 2026, gas supply will fail to meet peak days and individual states and regions will run short.
However, piping gas from northern Australia to the south is expensive and difficult to set up.
Up to 142 petajoules of gas will be needed in 2025 from Queensland and the Northern Territory to support the southern states, which will create significant infrastructure constraints and require pipeline expansions, EnergyQuest reported.
“Supply from Queensland would need to increase to nearly one third of southern supply to fill the gap. However, moving this volume of gas south would run into constraints on the QSN Link Pipeline and the Moomba-Sydney Pipeline,” the firm stated.
EnergyQuest chief executive officer Dr Graeme Bethume said Queensland also has investment risks.
“Maximising production from Queensland’s coal seam gas (CSG) fields requires investors to be sufficiently confident of the investment climate to drill around 1,000 new wells a year at a total cost of A$1-2 billion,” he said.
Dr Bethume said investors already feel over-exposed to Queensland’s CSG projects, noting how Arrow Energy has lost more than A$6 billion on its investment since 2010.
“It would hardly be surprising if [investors] are cautious about further investment but any pull-back on drilling or development could easily make the situation worse,” he said.
Competitive gas prices
As well as being located near major demand centres and being well-suited to meeting peak demand, EnergyQuest’s report found that LNG import terminals could provide long-term contracts to gas users with transparent pricing.
Such terminals will also provide increased competition in the east coast gas market, something which is otherwise likely to decline, the firm reported.
According to its latest energy quarterly, released this week, domestic gas prices in Western Australia averaged $3.53 per gigajoule in the 2018 fourth quarter – below the Henry Hub average of $4.95/GJ.
However, east coast prices surged more than 42% on the same period in 2017, to average $10.01/GJ.
Dr Bethune said the start-up of Queensland’s three Gladstone LNG projects, which currently supply 25% of domestic east coast gas, automatically linked the east coast market directly to global gas market prices and demand, where LNG prices are set.
“There are fears that [import] projects will lock the east coast into international gas prices but that has happened already,” he said.
“Queensland gas delivered to NSW and Victoria is already priced at export parity. The differences in price with LNG imports are between export parity plus pipeline tariffs for domestic gas and import parity for imports.”
“More importantly, if imports do not go ahead, the east coast will be short of gas with limited suppliers who do not have the restraint of active competition in setting their prices,” Dr Bethune added.
The firm also warned that transporting more Queensland gas to the south would only be a short-term fix as the state has its own challenges.
“We also expect Queensland gas production to start declining from 2025, due to a shortage of quality gas resources,” Dr Bethune said.
According to the agency’s east coast gas outlook, there would be no known 2P (proved and probable) reserves to meet the market’s demand after 2026.
Production from Queensland’s CSG fields is expected to fall by more than 100PJ a year in deliverability – the equivalent of one LNG import terminal every year.
This in turn will force a cut in output from six to four LNG trains at Gladstone, EnergyQuest said, claiming LNG imports were the “only certain supply option for the east coast after 2026”.
Australia would not be the first country to adopt such a conflicting idea. Other countries including the United States, Malaysia, the United Arab Emirates and Egypt already export and import LNG.
Dr Bethune said LNG importing does not necessarily have to be “forever”.
“Both Argentina and Egypt went from exporting LNG to importing and are now back into exporting following substantial gas discoveries,” he said.
EnergyQuest’s report concluded that “in light of the range of risks, developing LNG import terminals sooner rather than later would be a prudent form of risk mitigation”.
“Timing is critical, and it is concerning that the regulatory processes in Victoria and NSW are dragging out, delaying decisions to go ahead with these new terminals,” Dr Bethune added.
“Here, we have investors willing to spend their own money to alleviate the east coast gas shortage but there does not appear to be any sense of urgency on expediting the approval process.”
The report also pointed out that the development of domestic gas projects is critical and should be more competitive with imports.
“For example, development of Santos’ (ASX: STO) Narrabri project in NSW is necessary but is being hampered by a lengthy regulatory process and political uncertainty,” Dr Bethune noted.
Speaking at the Australian Domestic Gas Outlook Conference in Sydney on Tuesday, Australian Competition & Consumer Commission (ACCC) chairman Rod Sims said the government has an important role to play to ensure gas is brought to market sooner rather than later.
“We continue to urge state governments to adopt policies that consider and manage the risks of individual gas development projects, rather than implementing blanket moratoria and regulatory restrictions,” he said.
“Where new smaller players like Blue Energy (ASX: BUL) in the Bowen Basin are willing to take on the risk of new pipeline or gas developments, governments should be looking to do what they can do to facilitate a vibrant competitive gas market that will benefit the whole of the Australian economy.”
Mr Sims also believes a great diversity of suppliers are needed in the south to bring domestic gas prices down.
“The most substantial pricing benefits for domestic gas users will be achieved if additional lower cost gas is produced in the south, rather than transported from Queensland, the Northern Territory or imported via an LNG import terminal,” he said.
So, while this might be true, until development restrictions are lifted in the south (if ever), imports could just be the quick fix to both supply and pricing issues.