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LNG Bulletin, December 2023

7 December 2023

Welcome to the 2023 edition of the HFW LNG bulletin. This edition includes articles on the current status of the LNG industry in Australia; the potential sources for dispute in an LNG market which has undergone rapid development and which is now characterised by tight supply, price volatility and fragile balance; the drivers behind the shifts in the global LNG market and how market dynamics are changing in Asia; a number of recent cases on delivery and redelivery notices under charterparties; and an update on the progress and impact of the EU’s LNG benchmark.

LNG – what is going on down under?

In 2022, Australia was the global leader in LNG export capacity, with a reputation for stable and reliable energy policy. One year later, and there are reports of Australia quietly quitting1 the LNG business. More recently, news of industrial action at LNG projects operated by Woodside and Chevron in Western Australia sent European (TTF) prices surging. What is going on down under?

The Australian LNG market(s)

Australia is a very large, relatively sparsely populated, federated country. Those circumstances have resulted in two distinct gas markets, one on each side of the country. There is no pipeline connecting these two markets, nor are there any LNG import terminals (yet). Significantly, different policy decisions have been made by State and Federal authorities to foster gas developments in each market.

The West Coast gas market (comprising the State of Western Australia) has four on-shore liquefaction facilities, with multiple production trains: North West Shelf, Pluto, Gorgon and Wheatstone, and one floating off the coast (Prelude FLNG).

The East Coast gas market (comprising all the other States and Territories of Australia) has five on-shore liquefaction facilities (also with multiple trains): Darwin LNG and Ichthys in the Northern Territory, and GLNG, QCLNG and APLNG in Queensland.

In total, the ten liquefaction facilities have a combined LNG export capacity of 87.6 million tonnes per annum (second globally, behind the United States). Almost all of this LNG is shipped to buyers in Japan, China, South Korea, and Taiwan; although at least one spot cargo from the North West Shelf has made the long voyage to Europe.

The amount of LNG available for export from Australia is closely connected to the stability of domestic gas supply. This connection makes LNG exporters subject to varying degrees of State and Federal government intervention. In addition, when domestic gas prices are high, the LNG exporters become easy targets for politicians, large commercial and industrial gas buyers, the press and the general public venting their frustrations.

The West Coast gas market

The DomGas Policy

Since 2006, Western Australia has had in place a domestic gas reservation policy (the DomGas Policy) in respect of its off-shore gas reserves which are exploited through on-shore or near-shore facilities. The DomGas Policy has three limbs:

  • reserving domestic gas equivalent to 15% of LNG production from each LNG export project.
  • developing and obtaining access to the necessary domestic supply infrastructure (including a domestic gas plant, associated facilities and pipelines) to process and deliver that gas.
  • demonstrable diligence and good faith in marketing gas to existing and prospective customers.

When an LNG project requires an access arrangement with the State government for land and other approvals (in the form of a State Agreement), the project proponents must commit to the DomGas Policy.

The DomGas Policy has been resoundingly praised by many commentators. Domestic gas prices in Western Australia have for many years been lower than on the East Coast, where the competition for gas supply between LNG and domestic consumption has exposed consumers to LNG net-back pricing.

It does however have its problems. A number of the State Agreements do not specify when the 15% of LNG production must be offered domestically. That has led to a concern that certain LNG projects are leaving their domestic commitment to be fulfilled to the end of the project, when gas reserves are less certain. In the face of recently rising domestic prices, there is also a call by domestic buyers for more transparency in domestic gas sales to ensure the “good faith in marketing” limb of the DomGas Policy is being observed. These problems have led to a recent inquiry into the adequacy of the policy by the Western Australian State Parliament. The report of findings and its recommendations are expected before Christmas 2023.

Export of on-shore gas reserves

Western Australia also has significant on-shore gas reserves. The State government has not typically permitted gas from on-shore fields to be exported as LNG. However, controversially, the Mitsui and Beach Energy “Waitsia State 2” project did receive such an exemption for 50% of the reservoir for the first five years of the project. A number of other on-shore producers have also sought an exemption from the State government to no avail.

Industrial action

More recently, workers at Woodside-operated North West Shelf platforms and Chevron-operated Gorgon and Wheatstone platforms engaged in industrial action to secure improved pay and conditions. Both companies reached a deal with the unions, in August and October 2023 respectively. As evidence of the butterfly effect in action, European gas markets reacted to this threat of disruption to Western Australian LNG projects by surging up to 28% day-on-day in early August 2023. A number of reasons for this have been reported, including a concern that Asian buyers would look to secure Northern Hemisphere LNG production, otherwise destined for Europe, in order to cover any shortfalls in supply from Australia.

The East Coast gas market

Domestic supply – the ADGSM

Domestic supply is ensured by the threat of the federal government triggering the Australian Domestic Gas Security Mechanism (ADGSM). The mechanism, which is considered a measure of last resort, empowers the Federal resources Minister to direct that LNG projects limit exports of LNG.

In late 2022, spot and short contract gas prices increased dramatically in the East Coast gas market. This was attributed to the Russia-Ukraine war affecting international LNG prices, high gas demand due to cold weather in the south-east of the country, unexpected outages at coal fired power stations, and supply issues for coal for power generation.

To avoid the triggering of the ADGSM (and the consequent sovereign risk and force majeure risks), on 29 September 2022, the three Queensland LNG projects (GLNG, QCLNG, and APLNG) signed a heads of agreement with the Federal government, providing for uncontracted gas destined for export as LNG to first be offered to the domestic market, with reasonable notice and on competitive market terms. The agreement expires on 1 January 2026.

Domestic supply – temporary price cap and Mandatory Gas Code of Conduct

The ADGSM was not the full extent of government intervention in the East Coast gas market in response to the increased spot prices. In December 2022, the Federal government imposed a temporary price cap of $12/GJ on new domestic wholesale gas sales by East Coast producers. (The cap also applies to any amendments of the gas price under existing gas sale agreements.)

The price cap was quickly followed by the implementation of a Mandatory Gas Code of Conduct on 11 July 2023, following amendments to the Australian Competition and Consumer Act. The Code also contains a price cap, initially set at $12/GJ, designed to anchor negotiations for new gas supplies. It also contains transparency obligations to increase visibility of the amount of uncontracted gas available for sale and obligations to deal in good faith.

Unlike the temporary price cap, the Code also contains a number of exemptions (including for large gas retailers), which large commercial and industrial buyers have complained reduces its effectiveness.

The combination of the temporary price cap and Code have also had the effect of stalling new sources of domestic gas supply while the impacts of the government intervention are assessed. This results in a heavier reliance on gas earmarked for export as LNG to fill supply shortfalls in the East Coast market, particularly as production from fields that only produce gas for domestic consumption continue to decline.

Australia wide

The Safeguard Mechanism

The Federal government has pledged to cut greenhouse gas emissions to 43% below 2005 levels by 2030. The legislation to implement that pledge is the National Greenhouse and Energy Reporting Act 2007 (called the “Safeguard Mechanism”).

Significant reforms to the Safeguard Mechanism came into force on 1 July 2023. The enhanced Safeguard Mechanism requires that all new LNG projects (and new fields that come online to supply existing LNG Projects) must have “zero reservoir carbon” during development. In other words, the new LNG projects must have net zero carbon dioxide emissions from their first day of operation. Further, existing LNG projects that emit more than 100,000 tonnes of carbon dioxide equivalent per year must reduce their scope 1 emissions by 4.9% below their “baseline levels” each financial year. Emissions reductions can be met via decarbonisation opportunities and by purchasing offsets within Australia.

New LNG projects – challenges

The Safeguard Mechanism will have an impact on producers looking to commission new LNG projects in Australia. This includes Woodside (in respect of the Scarborough and Browse projects off the coast of Western Australia) and Santos (in respect of the Barossa project off the coast of the Northern Territory), although the legislation would have been anticipated by these companies to some degree.

In addition, both Woodside and Santos are fighting court cases which have been mounted on social and environmental grounds in relation to the Scarborough and Barossa projects. The progress of both projects has been delayed by interim injunctions as a result. Both cases are expected to be heard next year.


It was as a result of the government interventions discussed above that the head of INPEX suggested that Australia was in the process of quietly quitting the international gas trade earlier this year. The Federal government has acted to assuage those concerns via various diplomatic channels, but there is little doubt that the Australia’s reputation as a stable and reliable energy supplier has been marred. The LNG industry in Australia has experienced a tumultuous 12 to 24 months, and there is no sign of calmer waters ahead.

Paul D Evans & Peter Sadler


“Beyond the Golden Age of Gas”: LNG trading disputes in a new context

In its Medium Term Gas Report, published in October 2023, the International Energy Agency (IEA) gave the executive summary the following title: “Beyond the Golden Age of Gas: Slower growth, higher volatility and greater uncertainty.” The report included the following assessment: “while market tensions eased in the first three quarters of 2023, gas supplies remain relatively tight and prices continue to experience strong volatility, reflecting a fragile balance in global gas markets”.1

This description marks a significant change for the LNG market and will lead to a number of knock-on impacts. A market characterised by greater volatility and greater competition for supply will also be characterised by a greater number of disputes. Further, in a finely balanced market, the effect of disruption or incident is magnified and the fear of this makes participants more sensitive. In this context, we consider where and why disputes might arise as we head into 2024.

A major and ongoing source of concern remains that of geopolitics. The war in Ukraine continues to put pressure on the global energy market as we head into winter. The imposition of sanctions and restrictions both by and against Russia has already led to a number of disputes in the market. In addition, the conflict in the Middle East and the potential for tension between China and a number of countries all create risk and uncertainty.

Next, the fine balance in the market creates potential for disruption caused by construction and/or operational issues at LNG facilities. As is reflected elsewhere in this bulletin, local issues can create global problems. Illustrations of this come from the impacts of the fire at Freeport’s liquefaction facility on Quintana island last summer and the industrial action in Australia this summer, both of which spooked the European LNG market.

The burgeoning US LNG industry is one to watch. The very fact that the US has become a global exporter at scale so quickly is a potential source of disputes in several ways, including construction and teething problems at new facilities. In addition, the scale and speed of development is giving rise to political, environmental and regulatory issues. On the Gulf Coast, some LNG projects, including some already under construction, are facing regulatory challenges and political pressure as environmental groups seek more consideration for their impact on the climate. In November, a US court removed an emissions permit for an LNG export terminal under construction in Texas and sent the permit application back to the Texas Commission on Environmental Quality to be re-evaluated.

Looking ahead, the recent decision by the EU to place methane emissions limits on oil and gas imports into Europe from 2030 is likely to have a significant effect on US exporters, given that the US is the biggest supplier of LNG to Europe.

More immediately, drought has led to restrictions on vessels passing through the Panama canal. This has caused delays, affected freight rates and increased the cost of LNG supplied from the US to Asia. If the situation continues – and/or worsens – this could put pressure on supply.

All of these pinch points – and others – could give rise to disputes. This is all the more likely because the global market has grown and changed so fast. What was once a stable market with relatively few participants in long term relationships has now expanded to be globalised and interconnected, with many more participants and an active spot market. As discussed elsewhere in this bulletin, the market is gradually developing – including with the arrival of Asian and European benchmarks – but it is still adjusting and there will be risk associated with that. There will also be a number of contracts between new parties with a less well-established trading relationship. When contract performance is affected, for whatever reason, newer contractual relationships come under particular pressure. This is well-illustrated by the high-profile disputes in relation to the length of the commissioning period and the destination of shipments coming from the new Calcasieu Pass export plant in Louisiana.


Tight supply, price volatility and fragile balance will inevitably give rise to contractual disputes in the LNG market in relation to disruption of supply, pricing issues, defaults and declarations of force majeure. Parties can plan ahead by identifying the main risks in their key contractual relationships and stress-testing the relevant provisions in those agreements. Preparation is always critical to success in dispute resolution.

Andrew williams & Amanda Rathbone


The continuing evolution of the Asian LNG market

The global LNG markets are evolving. In this piece, authored jointly by HFW Singapore partner Dan Perera, together with S&P Global Commodity Insights’ Eric Yep and Shermaine Ang, we examine the drivers behind the shift, and how LNG market dynamics are changing in Asia.

Returned (relative) stability

In HFW’s December 2022 article, The LNG market and energy security in Asia 1, we discussed the development of new LNG receiving terminals under construction across Asia, as many states in the region looked to turn their backs on the burning of coal for energy following the COVID-19 pandemic. LNG previously intended for those new receiving terminals was instead making its way to Europe, together with some of the floating storage and regasification units (FSRUs) which their infrastructure had intended to rely on.

Several months later, we have seen global demand for LNG – and the prices attaching to it – normalise somewhat, after the previous 18-month-long wild ride in the markets. As new sources of supply came on stream, and as storage capacity across Europe filled up and did not rapidly deplete – thanks in part to a mild winter – a semblance of calm has now returned to global LNG markets. For how long that situation may prevail, however, is anyone’s guess – geopolitical tensions continue to have an impact.

We have now reached the stage where a number of LNG receiving terminals previously under construction have been completed and successfully commissioned. Examples include those in Vietnam and the Philippines, which are now successfully receiving LNG and feeding into their respective national grids. As such, the LNG market in Asia has indeed continued its ongoing evolution, on its journey to become a major hub for the consumption of LNG – an interim fuel of choice for several states in the region, as a move towards sustainable energy transition slowly plays out.

Demand outstripping regional supply in Southeast Asia

Southeast Asia is expected to rely increasingly on LNG imports due to several factors. Chief among these is the long-term decline in domestic gas production and the difficulties faced by the national oil companies in rejuvenating their upstream assets, even as their economies continue to grow and energy demand continues to rise.

Singapore, Indonesia and Malaysia are expected to see their LNG imports continue to rise, especially Singapore, where LNG will remain a source of energy security due to the lack of viable alternatives. In June 2023, Singapore’s Sembcorp Industries signed a new piped gas contract with Indonesia’s Medco Energi Internasional, and the Energy Market Authority is separately evaluating a tender for a dedicated FSRU in the city-state. These actions are driven by uncertainty over pipeline gas supply from neighbouring Indonesia and Malaysia, as legacy pipeline contracts expire, and the supplier states themselves face rising gas demand.

Indonesia and Malaysia, the stalwarts of Southeast Asia’s oil and gas production, are gradually turning into importers of LNG, forcing national oil companies Pertamina and Petronas to find a balance between meeting supply commitments to long-term LNG customer markets, such as Japan, and the urgency of domestic demand. Indonesia’s Tangguh LNG terminal is already a key supplier of cargoes to the domestic market, and Malaysia has seen a jump in LNG imports in Pengerang. Both countries are working on upstream projects to reverse production declines, but it remains a challenge, and for Indonesia the start-up of flagship LNG projects like Abadi and Indonesian Deepwater Development (IDD) still appears to be several years away.

On 2 October 2023, Italy’s Eni announced that its Geng North-1 deepwater exploration well in the Kutei Basin offshore East Kalimantan had discovered significant amounts of gas and condensate, estimated at around 5 Tcf of gas in place with 400 million barrels of condensate. Geng North-1 is believed to be the largest discovery in Indonesia in at least two decades, although further appraisals will be needed, according to S&P Global Commodity Insights. The immediate route to commercialise Geng North would be to utilise available capacity at the Bontang LNG liquefaction plant, and also supply the domestic market. So, there is still a chance that Southeast Asian gas production decline can be arrested, amid broader constraints on new oil and gas investment.

For Vietnam and the Philippines, the two new LNG importers of 2023, LNG is also needed to replace the lack of domestic gas supply and, in the case of the Philippines, the depletion of the Malampaya gas field. It is understood that LNG importers in both countries are still awaiting regulatory certainty on downstream electricity market regulations before they can commit to execute LNG Sale and Purchase Agreements (SPAs). Rigid state-owned power purchasing utilities in both countries do not have a mechanism to deal with prices of electricity generated from LNG, resulting in the lack of power purchase agreements or PPAs. The absence of PPAs mean that the power producers cannot sign long-term agreements with gas importers, who in turn are unable to sign long-term LNG deals
with international suppliers.

Thailand is still struggling with production declines at its largest gas fields, including Erawan and Bongkot, and uncertainly in pipeline gas supply from neighbouring Myanmar. It emerged as one of the most stable spot market LNG importers in Southeast Asia, despite much price volatility following the Ukraine crisis, mainly because Thailand is fairly insulated from higher costs as electricity tariffs are adjusted every four months.

Before Vietnam and the Philippines, Myanmar was one of the fastest new LNG developments to come to market, having set up a complex LNG import and power production supply chain, while the rest of the world was dealing with COVID-19. Myanmar’s LNG import project navigated logistical issues, such as the low draft at the Yangon River, and conducted small-scale LNG carrier shipments to feed power plants in Yangon. However, it has now been impacted by the higher cost of LNG and recent political turmoil. Prices remain a major challenge in making LNG affordable.

Market liberalisation driving demand

Across most of the Southeast Asian region, gas market and power market liberalisation is a critical theme that will underpin future gas demand, in the form of pricing policies as well as third party access to LNG terminal infrastructure. New LNG importers are waiting in the wings to dislodge the national oil companies which have to date monopolised imports. In September, on the first day of the Gastech 2023 conference in Singapore, major LNG trader Gunvor announced a 0.5 million mt/year LNG SPA with Hin Kong Power, a joint venture between Gulf Energy Development and Ratch Group. Hin Kong Power was among the first private companies to sign a term LNG supply contract for Thailand, although power utility EGAT has been supplementing PTT’s procurement efforts in recent years, and several others are awaiting their turn.

Small parcel cargoes

One of the more subtle developments in the region has been the development of downstream LNG distribution infrastructure to supply smaller volumes, break large cargoes into smaller parcels and conduct LNG bunkering or reloading activity. An increasing number of LNG receiving terminals like Pengerang, Melaka, Bintulu, Map Ta Put, Arun and Singapore have built out these capabilities over the years. China’s LNG importer JOVO has been splitting LNG cargoes into smaller parcels at Subic Bay in the Philippines for several years, and Singapore and Cambodia both have existing capability to distribute LNG in small ISO tanks for a variety of industrial purposes, expanding LNG consumption beyond just power generation. This is a space that will continue to evolve as gas markets find a firmer footing.

Decarbonisation drive

Perhaps the most significant long-term trend that impacts LNG is the evolution of Southeast Asia’s energy mix amid growing pressure to decarbonise. Vietnam has been promised around US $15.5 billion under a Just Energy Transition Partnership with wealthy nations, in return for setting up an energy transition roadmap to decommission coal-fired power plants. Indonesia has been promised around US $20 billion under the same programme. Reaching Southeast Asia’s latest decarbonisation targets will call for extensive transformation of its power generation sectors, and local governments are stepping up renewables targets to meet power needs, targeting around 68 GW of wind and solar capacity additions from 2021 to 2030, according to S&P Global analysts.

The rise of zero carbon fuels will be a challenge for LNG demand. The Singapore energy regulator, EMA, is proposing to require all new and repowered power generation units to be at least 30% volume hydrogen compatible, with the ability to be retrofitted to become operationally 100% hydrogen compatible in the future, Tan See Leng, second minister for trade and industry, announced recently at the Gastech 2023 conference in Singapore. A few weeks ago, Malaysia launched its Hydrogen Economy and Technology Roadmap (HETR) to guide the development of its hydrogen economy.

Overall, however, Southeast Asian energy companies are still seeking more LNG and demand will most likely continue to grow in coming years.

New Southeast Asia price marker

The establishment of new LNG markets in Southeast Asia in particular has also led to the development of a new regional LNG pricing benchmark, in the form of the S&P Global Commodity Insights’ DES Southeast Asia LNG Marker launched on 23 October 2023. This complements S&P Global Commodity Insights’ existing Asia offerings, such as Platts Japan Korea Marker (JKM), and Platts West India Marker (WIM).

The Platts Southeast Asia Marker, or SEAM 2, reflects the value of spot LNG cargoes delivered into Southeast Asia. These assessments are published as a differential to Platts JKM as well as on an outright basis.

In the past 2 years, Southeast Asian (Thailand, Singapore, Philippines, Vietnam) LNG imports have grown to 14.3 million MT year to date as of 16 October 2023. This growth has been led by Thailand, with imports jumping by 24.7% in 2022 from 2021. Year to date import figures in Thailand and Singapore have also exceeded its 2022 imports by 13.6%.

With the start-up of new receiving terminals in Vietnam and Philippines, LNG imports into the region are expected to increase further and play a crucial role in the nations’ decarbonisation efforts.

Further to that, major international players have also indicated interest in trading or selling into Southeast Asia to tap into the new emerging buyers in the market.

The table below sets out the standard terms and specifications for SEAM.

Term Standard
Basis and location Thailand considered basis of assessment, prices of LNG spot cargoes delivered into Singapore, Philippines or Vietnam may be normalised.
Timing Delivery in third, fourth, fifth and sixth half-month cycles forward from date of publication. SEAM monthly assessment based on average of the two DES Southeast Asia LNG half months that match the JKM delivery month period.
Delivery window Typically three days long, buyer’s option to narrow to a one- or two-day delivery window by 30 days before first day of traded delivery window
Loading location Seller’s option to nominate base loading port, may substitute loading port up to 30 days prior to first day of traded delivery window
Quality GHV of 1,000-1,150 Btu/Scf. Platts may normalize information with other ranges for quality.
Quantity 3.4 TBtu plus/minus 5% operational tolerance, at seller’s option