Australia’s LNG export industry took off in 2015 and continues to grow. Gas producers had the choice of exporting or selling gas domestically. As a result, the prices on domestic markets are now influenced by international gas prices.

The main production basin in eastern Australia is the Surat-Bowen Basin in Queensland. There are also smaller basins in south Australia, New South Wales, off the coast of Victoria, and in the Northern Territory. Together, these basins account for 37% of Australia’s total gas production.

The eastern gas market is interconnected by transmission pipelines, which source gas from these basins and deliver it to LNG facilities for export and to large industrial customers and major population centres for domestic use.

According to the Australian Energy Regulator’s (AER) State of the Energy Market 2022 report, the east coast gas markets have entered a period of sustained high prices and tight supply. ‘Over late 2021 and particularly since April 2022, gas prices in east coast markets rose to and persisted at record highs’, it says, in common with worldwide gas price escalation since Russia invaded Ukraine.

However, southern gas production continues to deplete reserves, ‘increasing the risk of shortfalls’, warns the report. It continues: ‘Overlapping factors in the national electricity market from early May 2022… drove an unanticipated increase in gas demand from this sector despite the gas price increases’.

Following Russia’s invasion of Ukraine, international gas prices surged and local gas contract pricing is now factoring in export parity prices. Curtailment of Russian gas supply to Europe drove up international LNG demand from alternative sources. The situation was exacerbated by the explosion at the Freeport LNG plant in June 2022, which took a significant amount of US LNG off the market. Seasonal factors are also strong drivers of international demand and prices for gas.

Around 70% of domestic gas production in eastern gas markets (excluding the Northern Territory) is exported and the balance is sold into the domestic market. Most of the gas produced in eastern Australia is exported as LNG, which is liquefied in Queensland.

Australia also operates five LNG projects in Western Australia and two in the Northern Territory.

In 2021, LNG exports earned Australia A$50bn ($39.8bn), making Australia one of the world’s largest LNG exporters. However, these export levels are expected to be overtaken by Qatar and the US over the next five years.

Major LNG projects  
Queensland’s LNG industry comprises three major projects, which source gas mainly from the Surat-Bowen Basin. The Queensland Curtis LNG project has the capacity to produce 8.5mn t/y of LNG and is operated by Shell in partnership with CNOOC and Tokyo Gas. The Gladstone LNG project (a joint venture of Santos, Petronas, Total and Kogas) has capacity to produce 7.8mn t/y, while the Australia Pacific LNG project has the capacity to produce 9mn t/y (co-owned by Origin Energy, ConocoPhillips and Sinopec). Together these projects control over 80% of the reserves in eastern Australia. Gas is also sourced from other producers.

The Queensland Curtis Island LNG project has the capacity to produce 8.5mn t/y and is operated by Shell in partnership with CNOOC and Tokyo Gas
Photo: Adobe Stock

East coast LNG exports increased to record levels over 2021. China is the primary market for eastern Australian LNG, accounting for 67% of exports in 2021. However, since recent events in Europe, China has sourced additional LNG supply from Russia, increasing imports by 77% in the three months following the invasion of Ukraine.

In 1Q2022, exports to South Korea increased, but construction of new nuclear facilities is likely to restrain growth in gas demand over coming years. Japanese LNG imports also increased, but here again long-term gas demand is expected to decline with rising nuclear and renewable energy generation displacing gas-powered generators.

The AER’s report notes: ‘International price trend outlooks remain uncertain, influenced by potential COVID-19 lockdowns in China and the risk of further curtailments of Russian gas exports to Europe.’

Northern Territory and Western Australia  
In the Northern Territory, the Darwin LNG project has 3.7mn t/y capacity and the Icthys LNG project has 8.9mn t/y capacity. Both projects connect to the territory’s domestic gas market as emergency supply sources, but otherwise produce gas for export.

Western Australia has five LNG projects with a combined capacity of around 50mn t/y, including the North West Shelf, which is Australia’s largest LNG project of 16.6mn t/y capacity. The other projects are Gorgon (15.6mn t/y), Wheatstone (8.9mn t/y) and Prelude (3.6mn t/y).

Australia’s $54bn Gorgon LNG project is an important test case for carbon capture. US major Chevron won approval for the plant to store 100mn tonnes of greenhouse gas emissions in one of the world’s largest carbon capture and storage (CCS) facilities. The plant was considered to be a ‘standard bearer’ for CCS technology and potential decarbonisation.

However, Chevron, which runs Gorgon in a partnership with ExxonMobil, Shell and various Japanese companies, admits the plant has failed to lock away 80% of emissions generated in its first four years of operation as promised to the Canberra administration. Chevron blamed ‘technical challenges’ for a three-year delay to CCS operations, but suggested it has reached a ‘significant milestone’ with injection of 5mn tonnes of CO₂ into giant sandstone basins beneath Barrow Island, off western Australia, since 2019, according to a Financial Times report. The company said it is ‘confident of resolving problems with the plant’s $3.1bn pressure management system’.

As mentioned, gas supply to the northern gas market is largely supplied from Queensland’s Surat-Bowen Basin. But gas is also sourced from the Cooper Basin in southern Australia and from the Northern Territory. Southern gas is also transported north to meet LNG export demand. Gas from the northern fields is also used to supplement Victoria gas production to meet domestic gas demand in southern Australia over the winter.

To avoid export controls, Queensland’s LNG producers have entered into a series of Heads of Agreement with the Australian government, committing to offer uncontracted gas to domestic buyers on competitive terms before offering it for export. Faced with a reduction in southern reserves (largely due to the decline of the Gippsland Basin), expansion of the South West Queensland and Mooba-to-Sydney pipeline corridor is expected to play an important role in bringing northern gas supply to southern markets in 2023.

Long-term outlook uncertain  
Despite improved supply forecasts in the short term, the longer-term outlook remains uncertain, according to the AER report. In addition to further write-downs on 2P (probable and proven) reserves, the Australian Energy Market Operator (AEMO) forecasts that south-eastern gas production will drop significantly in 2023, leading to an increased risk of peak day supply shortfalls. By 2026, this is expected to occur more frequently – with no gas generation sometimes, while international conflict drives countries to diversify away from Russian gas is also driving up risk to accessing LNG imports and demand for floating storage and regasification units.

Similarly, the Australian Competition and Consumer Commission (ACCC) reports that a broader shortfall in supply from 2P reserves could emerge by 2026. Both organisations suggest the need for more exploration and development in southern Australia, pipeline expansions and LNG imports to mitigate supply risks. However, the AEA report points out: ‘The speculative nature of unsanctioned new domestic supply sources, with a range of barriers including [the need for] significant investment in infrastructure to bring gas to market, have led to producers finding it increasingly difficult to obtain finance to invest in fossil fuel projects.’

The AER report continues: ‘Further factors also contribute to uncertainty surrounding long-term supply conditions, including under-performance of developed resources and the potential for southern production to decline faster than expected.’ Indeed, the Australian Domestic Gas Security Mechanism empowers the energy minister to require LNG projects to limit exports or find offsetting sources of new gas if a supply shortfall is likely. And the Australian government is currently negotiating a new Heads of Agreement with gas exporters to safeguard Australia’s domestic supplies.

No gas importation terminals are operational currently on the east coast of Australia. This means that Australia currently can export but not import LNG. In early 2021, five new LNG import terminals were under consideration in New South Wales, Victoria and South Australia, aiming to resolve a forecast shortfall in gas supply in the southern states from winter 2023. However, delays have pushed out the potential availability of import supply to winter 2024.

Proposed LNG import projects include Australian Industrial Energy’s commitment to build a terminal at Port Kembla, New South Wales, which was initially scheduled to commence operations from late 2022–2024. Commissioning is now expected late-2023, with gas supply for winter 2024.

Squadron Energy has lined up the Hoegh Galleon floating storage and regassification unit. Meanwhile, Venice Energy has proposed construction of a terminal at Port Adelaide and claims it has signed its first customer, with construction scheduled for 2H2022, to deliver gas by winter 2024.

Vopak is considering feasibility of an import terminal in Port Phillip Bay in Victoria. Several gas market participants have signed Memoranda of Understanding in support of the project. However, AGL ceased plans for development of a proposed floating terminal at Crib Point, Victoria, as the Victoria Minister of Planning said it would have ‘unacceptable environmental effects’. Another project backed by ExxonMobil was also abandoned back in 2019.

Fracking opposition   
There have been significant regulatory barriers to gas development in some states and territories, with community concerns about the environmental risks associated with fracking. Concerted opposition has led to legislative moratoria and regulatory restrictions on onshore gas exploration and development.

Currently, Victoria, South Australia, Tasmania, Western Australia and the Northern Territory have onshore fracking bans in place, with varying degrees of coverage. The Victoria government banned onshore hydraulic fracking and exploration for mining of coal seam gas (CSG) or onshore oil until 30 June 2020. In March 2021, the Victoria government committed the ban on fracking and CSG exploration to its constitution. However, onshore conventional gas exploration recommenced from July 2021.

In 2018, South Australia introduced a 10-year moratorium on fracking in the state’s south-east. However, unconventional gas extraction is allowed in the Cooper and Eromanga basins, and there are no restrictions on onshore conventional gas in South Australia. The Tasmanian government’s ban on fracking has been extended until 2025. The Northern Territory has made 51% of the territory eligible for fracking. New South Wales has no outright ban on onshore exploration, but regulatory hurdles have stalled development proposals.