LNG Bulletin, 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.
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.
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.
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.
|Basis and location
|Thailand considered basis of assessment, prices of LNG spot cargoes delivered into Singapore, Philippines or Vietnam may be normalised.
|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.
|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
|Seller's option to nominate base loading port, may substitute loading port up to 30 days prior to first day of traded delivery window
|GHV of 1,000-1,150 Btu/Scf. Platts may normalize information with other ranges for quality.
|3.4 TBtu plus/minus 5% operational tolerance, at seller’s option
|LNG ship sizes of above 135,000 cu m
Harmonising LNG pricing
LNG continues to be priced differently across key consumption markets globally. This is partly due to how the LNG market and shipping practices have evolved over years, taking account of important factors in transportation such as boil-off and loss of cargo across long sea voyages, and the previously standard market dynamics of producers selling directly to end users. Those markets have now been significantly disrupted by a number of relevant factors, including:
- the arrival of many proprietary traders in the LNG space, which was previously the sole domain of the “tram lines” players
- a larger fleet of LNG carriers globally, permitting more capacity to be shipped
- global production capacity ramping up, with new projects coming on stream globally
- the development of LNG spot markets
- the ability to voyage charter LNG carriers
- technological developments, permitting increased compatibility between vessels and liquefaction plants and receiving terminals, including FSRUs.
- more short-termism driving the price fundamentals, leading to shorter-term supply arrangements under traditional long-term SPAs linked to energy security, and an increase in trading individual cargoes under Master Sale and Purchase Agreements (MSPAs). Parties which will be beholden to LNG as a source of national energy security for the next decades have been pushed into considering purchasing the product under MSPAs.
These changes in market dynamics have even had an impact on previously critical issues in LNG, such as price review disputes under long term SPAs. More SPAs are now being entered into for shorter periods, with extension options which may be triggered, but with supply obligations falling away if a mutually acceptable price cannot be agreed. As such, we would expect to see fewer SPAs containing price review provisions in their traditional form going forward, and the market is moving towards a position which reflects the greater number of supply sources and sell-side market participants, and which is geared more towards short-termism than it has ever previously been.
All of the above is evidence of the move towards the commoditisation of LNG, and greater standardisation globally regarding its handling and transportation. Together with greater commoditisation, comes the ability to price on a more standardised basis. This is an opportunity which S&P Global Commodity Insights have identified and utilised to propose the JKM Forwards assessments.
Along with a greater degree of standardisation observed in spot LNG trade, especially in North Asia, S&P Global Commodity Insights is also planning to launch a new price assessment for cargoes delivered one to three months after the front-month JKM assessment in the form of JKM Forwards. 3
The launch was proposed after market participants expressed interest in price assessments that reflect the value of physical forward LNG cargoes, whereby a full physical cargo of LNG would be delivered if a company trades a defined number of physical forwards with another company in one direction for the same delivery period. Similar mechanisms exist in forward crude oil cargo markets in Asia and Europe.
The level of standardisation of contractual terms in Asian LNG markets has enabled this proposed innovation as terms of physical cargo deliveries upon convergence will be aligned with existing JKM standard terms.
With a launch date of 16 January 2024, companies will be able to trade April 2024 for the promptest Forwards month and this would increase transparency of physical cargo value on the prompt through differentials against the Forwards assessments and further down the curve as well. These new assessments will be additional to the existing JKM Market On Close (MOC) infrastructure, and the assessment method remains unchanged.
The evolution of the LNG market in Asia brings with it a slew of new players to the space, including state-owned enterprises which will be feeding gas into national power grids for the first time. Developments such as the launch of the SEAM benchmark assist regional parties to price their LNG on a basis which best suits delivery to their region and to their terminal. It will be important for many of the new LNG market participants in Asia to take note of such developments and to seek to use them to their advantage, when negotiating for the supply of LNG going forward. How such parties approach the drafting, negotiation and pricing of LNG at this juncture will be of critical importance to the shape of the future Asian LNG markets and should not be approached lightly. States and state-owned enterprises should be ready to negotiate properly and in an informed manner with suppliers – be they producers or traders – if critical issues of national energy security are in issue.
New developments in the global LNG markets including the recent trader influx, and the development of more accurate and contemporaneous pricing benchmarks, may significantly alter the future market dynamics of LNG in Asia. As the number of players in the space continues to increase; as technology improves; and as the product takes on more of a commoditised nature, we may expect to see a greater degree of harmonisation globally in the LNG space. Utilising all levers available to maximise one’s position in the chain will be critical for those who wish to participate effectively.
Dan Perera & Eric Yep, Team Lead, Asia LNG and Energy Transition News, S&P Global Commodity Insights & Shermaine Ang, Global LNG Engagement Lead, S&P Global Commodity Insights
Delivery and Redelivery Notices: Simple, Right?
Most charterparties will require the owners on delivery, and the charterers on redelivery, to provide notices of the intended date of delivery/redelivery. The commercial purpose of such notices is clear – to give the parties time to plan ahead when the actual start and end dates of a charter are not fixed.
However, the legal implications of such notices have been uncertain for a long time and a recent spate of cases (both reported and unreported) in the last few years have brought these issues back into the limelight.
Specifically, in this article William, Rory and Florian will examine the following:
- What exactly is a “firm” notice?
- How do firm redelivery notices interact with final voyage clauses?
- Is the failure to give the requisite notices a breach of charter and, if so, how do you calculate damages? Is the Great Creation  LR 315 applicable?
The answers to these questions are surprisingly unclear when the giving and receiving of such notices is an act that occurs in virtually every single concluded charterparty. When claims do arise, they can be of significant value – particularly in sectors where hire rates have spiked – we have seen significant rate volatility across the container, LNG and tanker sectors across the last few years.
What exactly is a “firm” notice?
The Zenovia  LR 139 judgment is often quoted when redelivery notice issues arise. The case held that an approximate redelivery notice was not a promise that a vessel would be redelivered on the day stated, or that it would encounter no delay in the remaining employment under the charter after giving such notice (and effectively that it could be cancelled). All that is required is that notices have to be given honestly, in good faith and on reasonable grounds (based on the information available at the time the notice is given, which is subject to change). An approximate notice is therefore of limited commercial utility to the recipient. It would perhaps be unwise for an owner to make binding commercial or operational decisions on the basis of such an approximate notice. The Great Creation suggest the giving of redelivery notices simply prevents the charterers from being in contractual breach of their obligation to give notice.
However, the case did not consider “firm” notices and the effect of these has been a grey area ever since. The use of different words – “approximate” and “firm” suggests that there must be a difference between the two types of notice, leading some commentors to posit that a “firm” notice must be irrevocable/binding (i.e. it cannot be changed). There are a number of difficulties with that contention:
If that is the case, then why do charterparties often require the giving of (for example) 5/4/3/2/1 days’ firm notices? If the 5 days’ notice was binding/irrevocable (i.e. it could never be changed) then there is no need for 4, 3, 2 and 1 days’ notice. The requirement to send multiple firm notices would seem to be an industry acknowledgement of – as put by the arbitrators in The Zenovia - the “varied and haphazard” nature of shipping such that charterers cannot be expected to guarantee redelivery on a certain date.
The owners on delivery, and the charterers on redelivery, would then be undertaking to deliver/redeliver the vessel on that precise day (in 5 days’ time) and thus assuming all risk for the vessel being delayed, even if the reason was outside of their control (bad weather, slow discharge, engine breakdown, etc.). That would be an odd risk for the parties to adopt, particularly if the owners/charterers contractually have a longer period of time to deliver/redeliver the vessel. For example, the owners may still have another 10 days in the available delivery laycan, or the charterers may have a 2 months’ redelivery window but may have tendered their first “firm” notice for redelivery at the start of that window.
Delivery/redelivery before (as well as after) the stated date would also be a breach.
The writers have seen one unreported arbitration award in which it was advanced by owners that a “firm” notice was either a contractual election, a variation of the charter, a waiver/ estoppel or a freestanding new contractual obligation. The tribunal determined that a firm notice, when given, was an irrevocable contractual election and therefore binding. It is suggested this is an incorrect analysis and that none of these legal principles can apply to a “firm” notice, for the reasons below. Briefly:
- Irrevocable contractual election – what would be the point of (i) cancellation clauses on delivery; (ii) a redelivery range; and (iii) the requirement to send multiple firm notices, if the owners/charterers were bound to deliver/redelivery on one particular day by virtue of the very first firm notice they sent? There is also arguably no choice (election) to be made, such that the giving of a contractual notice could not be an election of one of those choices.
- Variation – the parties are not agreeing to “change” the original bargain by giving a firm notice, they are doing something required under the express contractual terms.
- Waiver/estoppel – is a party really giving up all of its contractual rights to deliver/redeliver on a date other than the date specified?
- Freestanding new contract – this doesn’t survive the usual offer, acceptance, consideration test.
It is, however, recognised as a counter argument that there must be some difference between firm and approximate notices.
Whilst judicial clarity will be welcomed, the writers suggest that a firm notice is one that needs to be given honestly, that there are no circumstances known at the time to suggest that the vessel cannot be delivered/redelivered on the date stated, and certainly that (in the case of redelivery) no other employment orders will be given or deliberate actions taken by the charterers that would frustrate redelivery in accordance with that notice (i.e. it is binding in the sense it cannot be cancelled in the same way as an approximate notice). Further, it should be acknowledged that there is no margin applied for a firm notice, but there is an acceptance that there still might be events outside of the parties’ control that delay the vessel. That is in distinction to an approximate notice, which is less accurate and must be judged by its “approximate” nature and which by necessity must have a margin of accuracy implied (e.g. in The Great Creation two days on a twenty days’ approximate notice or 10%) and which can be cancelled.
However, if the tribunal in the unreported case was right and a firm notice is an irrevocable election that cannot be changed, then both owners and charterers should exercise extreme caution when giving firm notices of delivery and redelivery. In an ideal world it would be prudent to have only a single firm notice that is given one day before delivery/redelivery with all other notices being approximate. Alternatively, express wording could make clear in the charter that firm notices can be changed, certainly due to circumstances outside a party’s control, and are therefore not an irrevocable election.
From the recipient’s viewpoint commercial decisions (e.g. an owner deciding on the next fixture after redelivery) should not normally be made basis receipt of approximate notices and even where a firm notice is received a window of flexibility should always be included in the next contract (e.g. the delivery laycan).
Firm notices and Last voyage orders
These are clauses that extend the contractual charter period (under a time charter) in the event a legitimate final voyage (i.e. one that was (legitimately) expected to be completed within the maximum charter duration) is delayed. The clause compensates the owners through the payment of additional hire for each day of the overrun.
The presence of such a clause in a charter would suggest that if charterers redeliver a vessel “late”, after the date stated in the charterers’ firm notice(s) then the owners would be compensated in agreed liquidated damages – additional contractual hire until the date of actual redelivery.
However, a recent unreported arbitration found that charterers are not entitled to the benefit of a last voyage clause after they have given a firm notice of redelivery. Accordingly, a notice clause (that merely states charterers are to give 5/4/3/2/1 days’ firm notice) cuts across and renders redundant the last voyage clause as soon as a firm notice is given, such that the owners’ losses must be calculated as normal unliquidated damages (rather than liquidated at the hire rate). Without express wording to that effect in a charter, that appears to be a surprising finding applying normal rules of contractual construction, but it is another point on which judicial determination will be welcome.
In the meantime, it would be recommended to have only a one-day firm notice and/or to make clear that a last voyage clause takes precedence over any firm redelivery notices clause.
Failure to give requisite notices and calculating damages
If a charterparty requires the giving of delivery and redelivery notices, then the failure to give any such notices, or compliant notices, may be a contractual breach of charter. The question is how should damages be calculated? There are two schools of thought/arguments.
The writers have seen arguments that The Great Creation decision means a failure to give the requisite number of redelivery notices (approximate or firm) entitles the owners to simply claim for damages for the period of notice that was not given at the charter rate, regardless of any actual loss. I.e. if the charterers fail to give the contractually required 20 days’ notice of redelivery and just give the vessel back immediately, the owners would be entitled to an additional 20 days’ hire.
Whilst at first blush that might appear an easy-to-use formula, it is suggested that you cannot make wider conclusions from what was a fact specific case (noting the award of hire in that case for the missing notice period actually operated as a cap on the owners’ damages claim – thus query if it can be justifiably used to quantify a claim as opposed to limit it). Further, such approach has the clear potential to violate the overriding compensatory principal of damages under English law. What happens if owners were never going to be able to charter their vessel immediately even if the correct redelivery notices had been given and the charterers were contractually entitled to redeliver the vessel on the date they did (that is to say it was not an “early redelivery”)? Surely awarding the owners 20 days’ additional hire would be giving them a windfall? A claimant must normally prove the breach caused a specific loss.
It is suggested the better approach is to apply the usual measure of damages, i.e. factually consider what the owners would have done had the correct redelivery notices been given so they are placed in the same position as if the contract had been properly performed. If factually the owners would not (or could not) have done anything differently then no damages would be due. Noting, as above, that you would normally be unlikely to fix out a follow-on charter against an approximate notice. Conversely, the damages award could be larger for owners than following The Great Creation outcome – perhaps they could have fixed a future charter at a higher daily rate or even sold the vessel at a higher price had they been given the requisite redelivery notices. However, this must be a question of fact in each case and it is suggested any general broad formula trying to use The Great Creation ruling to quantify claims in relation to redelivery notices is wrong and that, if anything, the point to take from this case is The Great Creation “cap” may operate to limit an owners’ damages claim (if the owners can first establish they have suffered a loss).
Again, judicial clarity may be needed but, in any event, the best advice for charterers is clear: do not take redelivery notices lightly; make sure the redelivery regime is followed precisely and always tender the notices required. Especially in the case of approximate notices - they have limited effect as stated above and accordingly provided they are given in good faith (basis the information available at the time they are given), the charterers should not be in breach. Extra care is needed with firm notices for the reasons set out above. The same lessons of course apply to owners giving delivery notices at the start of a charter, who would be equally advised to carefully consider the nuances of the notices they are giving and receiving.
William Gidman & Rory Butler & Florian Schacker
Progress of the EU LNG benchmark
In last year’s bulletin1, we reported that the European Commission (“EC”) was proposing a package of exceptional and temporary measures aimed at addressing high gas prices and ensuring energy security. Part of this package included the development of a new LNG benchmark. In this article, we set out what has happened since, consider the market reaction and assess whether the EC is achieving what was intended.
Russia’s invasion of Ukraine in February 2022 gave rise to a global energy crisis, as it severely disrupted the gas supply to Europe. European countries were left urgently seeking new sources of gas at short notice, and in intense competition with other importing nations. Some countries in the bloc were in a better position to do so than others. There was extreme and unprecedented price volatility in the global LNG market.
As part of the EC’s response, EU Council Regulation 2022/2576 of 19 December 2022 came into force on 13 January 2023 (the “LNG Benchmark Regulation”). It imposed a price reporting requirement with respect to LNG transactions to allow EU authorities to produce daily price assessments and an LNG benchmark. The aim was to improve market transparency and effectively, to lower wholesale prices for gas without distorting competition in the EU energy markets.
The LNG Benchmark Regulation tasked ACER 2 with creating an objective LNG price assessment tool by collecting real-time information on all daily LNG transactions. It also granted ACER the necessary powers to achieve this.
Who has been affected?
In brief, the reporting obligation applies to LNG market participants (i.e. persons engaging in LNG trading, irrespective of their place of incorporation or domicile) who engage in bids, offers or transactions for the purchase or sale of LNG:
- that specify delivery in the EU
- that result in delivery in the EU
- in which one counterparty re-gasifies the LNG at a terminal in the EU.
What must now be reported, when and how?
The specific data to be reported in respect of each transaction, bid and offer are set out in Article 21 of the LNG Benchmark Regulation and include details of:
- arrival window
- delivery terms
- timing information
Article 20 requires that data must be submitted daily to ACER “as close to real-time as technologically possible before publication of the daily LNG price assessment (18.00 CET).” Submission is done through “TERMINAL”, a new reporting system established by ACER.
Launch of daily price assessments and LNG benchmark
Based on the data received via this new reporting obligation, ACER published its first daily price assessments (DES LNG Spot for Europe (EU), North West Europe and South Europe) on 19 January 2023. This was later than planned due to an initial lack of data. It launched the daily LNG benchmark at the end of March 2023. 3 The benchmark is a spread of the daily price assessment for DES LNG Spot EU and the settlement price for the TTF Gas Futures front-month contract established by ICE Endex Markets B.V.
Is it working?
ACER updated its methodology for reaching the daily price assessments on 8 March 2023. It has also expressed concerns about the quality of data it is receiving, including issues with late and single sided reporting, inaccurate price reporting and mismatched information. In an open letter dated 27 July 2023 4, it identified the most commonly encountered data issues, offered guidance and urged market participants to be both “diligent, timely and accurate” and also proactive in detecting, reporting and correcting data quality issues. It nevertheless described the level of data quality at that time as “adequate/sufficient”.
The EC certainly seems to have confidence in its measures as in March 2023, it proposed amendments to the REMIT Regulation which included a permanent extension of ACER’s power to implement the LNG price assessment and benchmark.
In the longer term, the success of the benchmark price has yet to be seen because it will depend on whether traders and companies choose to use it. The initial extreme volatility in the market in 2022 steadied, in part thanks to a relatively mild winter. Currently in Europe, storage facilities are full. However, if there is a cold winter this year and demand spikes, or if other geopolitical factors have an impact, the LNG benchmark will be put to the test and we shall have a better sense of whether the EC’s package of measures have had the desired effect of addressing high prices and ensuring energy security for the bloc.
Adam Topping & Amanda Rathbone
- The European Agency for the Cooperation of Energy Regulators
- 2023_open_letter_LNG_data_quality.pdf (europa.eu)