Trend spotting

Tim Fourteau (Singapore), Alex Woody (Japan), and Yun Yong (Singapore), White & Case, discuss several trends in LNG SPAs and the broader LNG market.

The global LNG market is in a period of structural change. Demand is expected to surge across growth markets, particularly from Asia, and existing overcapacity on the supply side, particularly in North America, has seen LNG developers jostling to capitalise by offering shorter, more flexible and innovative, contractual structures. Against this backdrop, this article reflects on three trends in LNG Sales and Purchase Agreements (SPAs) and the broader LNG market.

Trend 1: The continued rise of JKM

Recently announced LNG SPAs have priced cargoes by reference to both Platts Japan Korea Marker (JKM) and Dutch TTF, reflecting the growing use of the JKM price benchmark for LNG imports into Asia. Historically, long-term LNG SPAs have been priced by reference to substitute energy sources in the market of import. In the Asian market, LNG imports were typically indexed against crude oil prices, factoring in the average weighted energy content of LNG relative to oil. In contrast to the Asian market, LNG imports into the US and Europe have been benchmarked against LNG’s most direct competing energy source in those markets – pipeline gas. Given the well-established gas market in the US, the price for LNG imports into the US was linked to the gas trading price at the Henry Hub, an access and connection point in the southern US for gas transmission pipelines (imports of LNG into the US were becoming necessary before shale discoveries in the US made the country an LNG exporter). Following the US shale boom, several import projects were converted and expanded to be export projects. These export projects tended to use a tolling or quasi-tolling model whereby LNG was essentially sold FOB at a price equal to a Henry Hub linked feedgas cost plus a fixed component to cover liquefaction cost plus margin.

In the initial wave of US liquefaction projects, a Henry Hub linked pricing model was attractive to Asian LNG buyers

because oil prices were, at the time the offtake contracts were made, at historic highs – according to EIA data, from 2011 to 2014, average annual oil prices were well over US$90/bbl. However, as oil prices receded, the shine wore off. Furthermore, given that Henry Hub is not representative of gas pricing in Asia, Henry Hub benchmarking created issues for Asian LNG buyers and spurred the search for a more accurate benchmark for LNG imports into Asia. An Asian benchmark price for LNG that has grown in popularity is the JKM benchmark. In early June of this year, the Intercontinental Exchange, Inc. (ICE) announced record activity in the use the JKM benchmark. It reported that the average daily volume in JKM LNG futures and options increased 14% y/y, and the number of participants trading JKM LNG futures increased 25% since May 2020. Since 2015, traded volumes of JKM swaps derivatives have increased around threefold each year.

Trend 2: The growing role of portfolio players and traders

Recently announced LNG SPAs also reflect the growing involvement of traders and portfolio players in the LNG market. LNG trade flows originally followed the producerto-consumer delivery model whereby gas and power utility companies, often from Japan and South Korea, would enter into long-term SPAs with the only, or primary, destination expected to be their home countries.

The LNG delivery model has been steadily shifting away from this point-to-point delivery model, as seen from destination free FOB contracts, equity lifting models, and the growing involvement of portfolio suppliers. The trend has been spurred by both commercial considerations and governmental action, such as opinions from the European Commission and Japan Fair Trade Commission regarding destination restrictions. Arbitrage opportunities in the LNG market have attracted trading companies that seek to capitalise on growing LNG demand and market liquidity. According to data compiled by Bloomberg, between 2016 to 2018, the largest three trading companies active in LNG more than doubled their LNG trading volumes and accounted for close to 9% of the global market. Between 2015 and 2020, physical LNG volumes traded on a short-term basis have almost doubled to 130 - 150 million tpy.

The growing involvement of traders is a positive development for the LNG market. Traders increase market liquidity by warehousing risk with longer contracts that they subsequently disaggregate and on-sell into the market on the basis of shorter or smaller deals.

Trend 3: Is a 10-year deal the new ‘long-term’ duration for LNG SPAs?

The average tenor of long-term LNG SPAs has decreased materially over the years. Traditionally, the average tenor of long-term LNG SPAs was around 20 years. According to the 2021 Annual Report of the International Group of Liquefied Natural Gas Importers (GIIGNL), the volume weighted average duration of long and medium-term contracts decreased from 16.4 years in 2018 to 11.7 years in 2020. GIIGNL recently reported that the majority of LNG SPAs signed in 2021 had terms of approximately 10 years, approximately half of which were with aggregators and traders.

Conclusion: Implications for project financing?

The development of medium to large scale gas liquefaction plants is capital intensive, and the capital expenditure required is usually measured in the billions of US dollars. The initial three trains of the 13.5 million tpy Cameron LNG in Louisiana, US, cost approximately US$10 billion, and the 2 million tpy Donggi-Senoro LNG Project in Indonesia cost approximately US$2.9 billion.

Given the amount of CAPEX required, private liquefaction plant developers have typically required limited recourse financing to fund the development of their projects. LNG SPAs or, for several US projects, tolling agreements, are the revenue-generating contracts that frame the tenor of the debt available for liquefaction projects, with the final debt maturity generally set years before the scheduled expiration of the LNG SPAs or tolling agreements underpinning the financing. For example, the Cameron LNG project in the US has US$7.5 billion, 16-year debt supported by tolling agreements with 20-year terms.

As noted above, the average tenor of long-term LNG SPAs has decreased materially over the years. This trend will be an interesting test of project financiers’ appetite to offer debt that extends beyond the term of the fully contracted offtake. Whilst lenders have historically shied away from this, they may get comfortable banking an uncontracted merchant ‘tail’, given the growing commoditisation and liquidity of the LNG market brought about by the involvement of traders and aggregators.

According to Paul Harrison, a project finance partner at White & Case Tokyo who recently advised the financiers on the landmark US$20 billion project financing of Mozambique LNG: “The trend towards commoditisation in an increasingly liberalised and liquid LNG market is well-established and it has been thought for some time that the logical next step in LNG project financing would be for lenders to take a higher degree of market risk. Developers of greenfield LNG projects have been looking to test lender appetite for medium-term LNG SPAs with re-contracting risk and for debt sizing credit for short-term/uncontracted volumes. Consideration has also been given to whether a borrowing base structure, typical in upstream oilfield financing, could be adapted for LNG. However, these structures have not gained significant traction to date.”

Paul also highlighted the effect of the energy transition on bankability considerations for LNG projects: “There is an emerging tension between the structural changes in the LNG market and the impact of the energy transition. Despite LNG traditionally being seen as the cleanest fossil fuel, the long-term future for the sector has become more uncertain as the energy transition has accelerated and this uncertainty will make it harder for lenders to take market risk.”

Whilst opinions differ on the future state of the LNG market, there is consensus that the LNG market is at a precipitous inflection point and will soon be dramatically different than the market we know today.

Note

Any views expressed in this publication are strictly those of the authors and should not be attributed in any way to White & Case LLP.