The recent approval of the Jordan Cove liquefied natural gas (LNG) export terminal by the US Department of Energy (DOE) represents another step towards the US becoming a major player in the international LNG market. Recent developments suggest that Asia could become a key destination for US LNG.


The DOE must grant LNG export licences (pursuant to the Natural Gas Act) to exporters who are delivering LNG to countries with which the US has a free trade agreement (FTA) without modification or delay. In contrast, before granting a non-FTA export licence, the DOE must consider whether the proposed export licence is inconsistent with the public interest.

There is political resistance to increasing the US’ LNG export capacity. The concerns are mainly focused around ensuring security of supply for domestic gas demand and the potential for increased LNG exports leading to higher domestic gas prices. In addition, public opinion is divided on the continued use of fracking techniques for shale gas exploration on environmental grounds.

Public and political resistance will continue to shape the DOE’s approach to the approval of LNG export licences (both in terms of how often export licence applications are approved and the substantive application of the public interest test under the Natural Gas Act).


So far the DOE has granted non-FTA export licences to the following five LNG projects:

  • The Sabine Pass project (Louisiana) was the first US LNG project to receive non-FTA export approval (in May 2011). The project has non-FTA approval for Trains 1 to 4, whereas Trains 5 and 6 only have FTA approval, which presents added regulatory risk. The project is wholly owned by Houston-based Cheniere and there are sale and purchase agreements in place with BG, Gas Natural Fenosa, Kogas, GAIL, TOTAL and Centrica. Some of the key provisions of the sale and purchase agreements include FOB pricing, a fixed liquefaction fee and a lack of price review rights for the buyer.
  • The Freeport project (Texas) was awarded non-FTA export approval in May 2013. The project is wholly owned by Freeport LNG Expansion and there are liquefaction tolling agreements in place with Osaka Gas, Chubu Electric, BP, Toshiba and SK E&S. In November 2013, the DOE gave conditional approval for an additional 0.4 Bcf/d to be exported from the Freeport project (1.0 Bcf/d less than the additional capacity requested by Freeport LNG Expansion).
  • The Lake Charles project (Louisiana) was awarded non-FTA export approval in August 2013. The project is a joint venture between BG and US natural gas company, Energy Transfer. Energy Transfer owns the liquefaction facility and there is a liquefaction tolling agreement in place with BG for the entire off-take.
  • The Cove Point project (Maryland) was awarded non-FTA export approval in September 2013. The project is wholly owned by Dominion Resources and there are terminal service agreements in place with Sumitomo and GAIL for the capacity.
  • The Cameron LNG project (Louisiana) was awarded non-FTA export approval in February 2014. The project is owned by Sempra Energy, GDF Suez, NYK, Mitsubishi and Mitsui. Toho Gas, a Japanese utility, recently signed a 20 year sale and purchase agreement with Mitsui for LNG produced at the Cameron LNG project.
  • The Jordan Cove project (Oregon) is the most recent LNG project to receive non-FTA export approval (in March 2014). Energy Projects Development Limited is the developer of the project, with the majority of the investment coming from Veresen (a Calgary based energy infrastructure company).

A further 24 applications for non-FTA export licences are awaiting approval (as set out in the table below). The DOE may consider the cumulative impact of the non-FTA export licences in the context of whether increased LNG exports to non-FTA countries are not in the public interest.

Furthermore, the US’ projected LNG export capacity is subject to the DOE’s discretion to revoke the non-FTA export licences if circumstances arise that threaten the public interest (such as high domestic gas prices).


The increased demand for LNG in Asia is the result of many factors, including population growth in the region and Japan’s shift away from nuclear energy. Asia now consumes over two-thirds of the world’s LNG (with Japan consuming one third alone).

One of the most significant factors driving Asian demand for US LNG is price. Typical long-term Asian LNG sale and purchase contracts typically link prices to the price of crude oil (using the Japan Crude Cocktail (JCC) index), although there have been calls from North Asian buyers for a move towards a separate and distinct pricing index for LNG in Asia (such as a pricing formula based around Platts Japan/Korea Marker (JKM), which is often used as the LNG pricing index for North Asia spot cargoes). In contrast, in the US, LNG is priced according to the Henry Hub price index (which is determined by supply and demand for natural gas in the US). The price differential between JCC and Henry Hub is potentially significant: some North Asian LNG importers pay approximately four times the amount paid for natural gas in the US. However, the export price increment is, in part, a product of (and should not be separated from) the associated liquefaction, processing and pipeline transportation costs.

A significant proportion of US LNG export projects have received investment from Asian buyers. Such investment is indicative of a wider trend: Asian LNG buyers are looking to secure long-term LNG supply at cheaper prices from the US. Recent examples include Pertamina’s 20 year supply contract with Cheniere which envisages Pertamina importing 0.8 Mtpa from Corpus Christi with first deliveries anticipated in 2018.

However, US LNG may not necessarily be the cheapest option for Asian LNG buyers, and US LNG projects may be affected by some of the challenges and risks we have outlined below.

  • Competition: US LNG exporters will face global competition from Qatar, Malaysia, Indonesia, Australian liquefaction projects and new export capacity in Mozambique and Tanzania. Some analysts predict that after liquefaction, processing and transportation costs, gas from Mozambique and Tanzania will be priced similarly to US LNG in Asia (but will benefit from greater proximity). In addition, Canada has attracted investment from Asian buyers, with Malaysia's state-owned Petronas committing to invest US$35 billion in order to construct and develop an LNG project in Canada. Notably, Canadian LNG exporters do not face the same restrictions as US LNG exporters when obtaining non-FTA export licences, which may be attractive to LNG buyers from non-FTA nations such as Japan. On the other hand, Canada does not have the US’ level of existing gas infrastructure and there is increasing political and environmental opposition to the expansion of Canada’s export capacity. In addition, Canada has smaller gas reserves than the US and its reserves are located further from the export terminals (therefore requiring the construction of more infrastructure to transport the gas).

  • US and global LNG supply shortfall: there is uncertainty as to when the US LNG projects (along with the Australian and East African projects) will begin operation (particularly if they are unable to secure long-term off-take commitment), which may have significant repercussions on price. Any delay could exacerbate the anticipated global LNG supply shortfall (which BG estimates will be 150Mtpa by 2025), which in turn may increase the price of LNG and could narrow the price differential between the Henry Hub index and the JCC index (depending on developments in the global oil industry).

  • Pricing of Asian LNG sale and purchase contracts: a shift from the JCC index or the gradual emergence of an Asian LNG spot market could reduce the price competitiveness of US LNG exports (especially given the additional transportation and liquefaction costs). As mentioned earlier, Platts has launched JKM as the index for spot ex-ship deliveries into South Korea and Japan. However, given the large capital investment that is required by major LNG projects (particularly the greenfield projects in Australia and East Africa), a substantial shift away from crude oil-linked pricing is unlikely (there is speculation that many LNG projects would not reach FID if their entire off-take was linked to natural gas prices). Whilst the Henry Hub price index may influence the pricing of Asian LNG sale contracts, over time it is uncertain that Henry Hub (which is historically volatile and based on factors which are independent of natural gas supply and demand patterns in Asia) will necessarily be an appropriate (or cheaper) way of pricing Asian LNG.

  • Demand factors: if Japan resumes operation of its nuclear power plants (or develops increased non-fossil fuel generating capacity), its demand for LNG will fall significantly. Tokyo Gas has estimated that if Japan successfully restarts its nuclear power plans this year, its annual demand for LNG will fall by 25Mtpa. An increase in coal usage (in response to low prices, which many believe will remain low for the foreseeable future) may also affect demand for LNG in Asia. Japan’s major utilities have recently increased their coal consumption, which may be indicative of a regional trend towards alternative sources of energy. However, if demand for LNG in Asia falls, there may be scope for US LNG exporters to negotiate supply agreements with European importers or deliver LNG on the spot markets (in comparison, Qatargas has recently extended its LNG supply agreement with Centrica and there is speculation that it is negotiating put options with several European import terminals to supply LNG, thereby hedging against the risk of falling demand for LNG in Asia).

  • Uncertain transportation costs: commentators anticipate that the widening of the Panama Canal (which is expected to be a significant shipping route of US LNG to Asia) will reduce transportation costs, but its full effect is unknown until tariffs or conditions of passage for LNG cargoes are confirmed.

  • Finance: not all of the US LNG projects have obtained the necessary financing for construction and operation of the terminals. On the other hand, access to the US debt and equity capital markets and the possibility of private equity investment (as obtained by Cheniere for the Sabine Pass project) may mitigate this risk.

  •  Delay and cost overruns: a skilled labour shortfall is expected in the Gulf of Mexico (where many US LNG projects are located), which may result in various cost overruns/delays, as has been the case for a number of the Australian LNG projects.


The US is on track to become a leading LNG exporter and Asian buyers will be keen to take advantage of the cost savings that US LNG potentially offers. However, the full potential of the US LNG market can only be realised if the various regulatory, economic and political challenges are overcome.

For further information in relation to any of the information or themes discussed in this article please do not hesitate to contact Stephen Murray, Reza Dadbakhsh (both of whom are qualified to advise on New York law), Richard Nelson, or Nick Kouvaritakis.


The order of precedence is the order in which the DOE will process non-FTA export applications. Applications received after 5 December 2012 will be processed in the order in which the applications were received (table up to date as of 24 March 2014).

Please click here to view table.