Prospects of LNG Exports From the United States to Japan

Prospects of LNG exports from the United States to Japan

Japan is world’s largest liquefied natural gas (LNG) importer. Japan’s LNG import was 3.18 trillion cubic feet (65.2 million tonnes) in 2009 [1] and is expected to reach 4.0 tcf in 2035 [2]. In fact, there is a distinct possibility that due to the recent disasters at the Fukushima I Nuclear power plant, Japan will opt for increasing its LNG import. This presents a unique opportunity for gas producers to sell more LNG to Japan.

Japan’s LNG Import Sources

Japan is intent on diversifying the sources of LNG import to get better control on LNG prices and attain reliability of supply in case of adverse weather/geopolitical events in any particular region of the globe. Japan’s LNG import by country in 2009 is shown in Table 1.

The main contenders to supply LNG to Japan are Qatar, Australia, Malaysia and Russia. Out of these, Russia’s contribution would definitely increase from 4.3% (Table1) to a higher percentage when Sakhalin-II LNG plant reaches its peak production and if the proposed Vladivostok LNG terminal becomes operational by 2017, although reliability of Russian supply will always remain a big question. Malaysia could be an eager exporter but it already supplies almost 20% of Japan’s requirement, therefore Japan may think of exploring other markets. Australia’s case is similar to that of Malaysia. In the case of Qatar, all the parameters appear to be satisfied except for the concern regarding long-term political stability in the Persian Gulf region.

Table 1
Table 1: Japan’s LNG imports by country, 2009 [3]

It makes sense, therefore, for Japan to review the possibility importing US natural gas. In fact, officials from TEPCO Trading Corporation and Chubu Electric Power Company in Japan have already shown interest in importing LNG from US producers [4].
At this stage it is worthwhile to consider several factors that would govern the feasibility of exporting US natural gas (in form of LNG) to Japan and other Far-East countries. Some of these factors discussed in this article are:

o US natural gas spare capacity.
o US liquefaction facilities.
o Financial feasibility of US LNG export.
o LNG Project Finance.
o Possible impacts of regulatory changes related to frac jobs and other risks for US LNG development.
US Spare Capacity

First, with regards to US natural gas spare capacity, currently daily consumption of natural gas in the US is approximately 62.4 Bcf/d while “technically recoverable” gas resources is estimated at 1,836 tcf out of which 616 tcf (unproved shale gas volume is 827 tcf per EIA, Annual Energy Outlook 2011) is attributed to shale gas [5]. If these results are combined with the Department of Energy’s latest determination of proved gas reserves, the US has enough natural gas for the next hundred years. It should be noted that spare capacity, in a capitalistic system, does not necessarily mean domestic production minus domestic consumption. In an open market, a commodity will chase the highest price quoted for it globally.

Table 2
Table 2: Forecasted gas production from Eagle Ford Shale [6, 7]

A quick review shows that all the large US shale gas basins are located far away from the US west coast. Also currently there is no facility on the west coast for gas liquefaction. Geographically, the Gulf of Mexico coast is the next coast line closest to the Far-East. Eagle Ford, Barnett, Woodford, Haynesville and Fayetteville shale gas basins are all located in states bordering the Gulf Coast.

Forecasted gas production from Eagle Ford shale, which is closest to the Gulf Coast, is provided in Table 2. The predicted growths in some of the other prominent shale basins are shown in Figure 1. These basins are easily accessible to both the liquefaction facilities proposed on the Gulf of Mexico coast. A rapidly rising production trend is evident from these forecasted data, which indicates that sufficient quantities of LNG could be exported if a reasonable net margin is assured to the producers.

Table 3
Table 3: Break-even costs at various shale gas basins

LNG Facilities

Second, at this stage let us examine the facilities on the US Gulf coast through which natural gas could be sent to Japan and Korea.

Freeport LNG and Macquarie Energy have planned to develop four liquefaction trains each with a capacity of 330 MMcf/d at Freeport LNG’s existing LNG import terminal on Quintana Island, 70 miles south of Houston, Texas. Following government approval, the start-up is expected in early 2015. The project is planned to draw shale gas from the Barnett, Haynesville, Eagle Ford and Marcellus basins.

Cheniere Energy’s Sabine Pass liquefaction project is being designed to permit up to four modular LNG trains – each with an average processing capacity of 466 MMcf/d. Subject to regulatory approvals and long-term customer contracts, LNG export is expected to commence as early as 2015.

These proposed export terminals will be located in one of the largest gas producing regions in the world, near two large natural gas trading hubs – the Houston Ship Channel and Katy – with access to the extensive US pipeline network. Moreover, with the opening of the Panama Canal to LNG ships in 2014, cargoes being exported out of Freeport/Cheniere will have a much shorter and quicker access to the Far-East, prime area for LNG demand.

LNG Export Economics

Third, a preliminary review of the economics of US LNG export is warranted. Such a review will scrutinize the conventional thinking that the disconnect between crude linked LNG and North American gas is the driver which encourages US producers to push for LNG exports. Towards that end, some calculations can be made to establish the cost of supplying LNG to Japan and Korea.

The breakeven prices of shale gas for four major shale gas basins are presented in Table 3. Now, at a minimum, by adding cost of transportation of gas to liquefaction facility, liquefaction cost, shipping cost, and storage & regasification cost, one can calculate the cost of natural gas at the point of unloading in Japan/ Korea:

o Delivery cost to liquefaction facility: Based on a typical maximum system-wide base rate for firm and interruptible transportation service of $0.20/MMBtu plus a 3% Fuel and Lost and Unaccounted For (LAUF) gas charge, the total variable cost per unit for transportation from processing plant to a liquefaction facility approximately 300 miles away can be estimated at $0.32/MMBtu [11].

o Liquefaction cost: In 2010, Cheniere Energy mentioned that it would charge between $1.40-$1.75/MMBtu for liquefaction [12] although according to Pan EurAsian, an advisor to the LNG industry, it appears to be $1 too high. ICF calculated liquefaction cost at $2.09/Mcf for a LNG plant in Russian Far East [13]. For the present study an average of the Cheniere fees, $1.58/MMBtu, has been considered.

o LNG Shipping cost: According to Brito and Hartley [14], the unit costs of LNG shipping have been reduced by 40 percent during 1997-2007. A shipping cost of $0.89/Mcf from Russian Far-East to the North American west coast has been considered in Ref 13 and is being used in the calculations here.

o Storage and Regasification cost: One IEA report [15] mentions that regasification could add $0.30/MMBtu to the price of imported LNG, while ICF International [13] points to a regasification cost of $0.38/Mcf.

If the cost of transporting the gas to a liquefaction facility, liquefaction cost, LNG Shipping cost and storage and regasification cost are added to an average breakeven cost of $4.00 (Table 3), the cost of natural gas post-regasification at a Japanese/Korean LNG facility will be ~$7.17/MMBtu. This value is somewhat higher than PFC Energy’s estimate of $5.55/MMBtu (it includes a storage and regasification cost of $0.38/MMBtu added by this author) for Western Canada natural gas delivered through Kitimat to Japan. The PFC estimate suggests a netback for the producer- owners of Kitimat of $2.93 to $7.23/MMBtu based on Japan Crude Cocktail (JCC) indexation and $60-$80 per barrel crude oil [16].

Figure 1
Figure 1: Production from five key US gas shale basins [8]

At this point a review of JCC prices in the near future is warranted. Japan imports most of its crude oil from the countries around the Persian Gulf. Oman crude oil futures at the Dubai Mercantile Exchange range between $105 and $110/bbl during the period May 2011 to December 2016 (this futures contract is used as a benchmark for Saudi Arabia, Iran, Iraq, the UAE, Qatar and Kuwait crude sold in the Asia-Pacific market). NYMEX WTI futures follow a similar trend. Given such expectations for future crude oil prices, the $7.17/MMBtu cost of LNG FOB Japan post-regasification as calculated above should provide any LNG exporter a significant net margin. Figure 2, extracted from Sempra LNG presentation, presents the Pacific Basin Premium, caused due to oil-index pricing, as a percentage of JCC.

It may be worthwhile to note here that Japanese import prices averaged $9.04 per million British thermal units last year. According to Daniel Muthman of E.ON Ruhrgas, most LNG long-term contracts are now priced at dollarper-MMBtu rate that is 14-15% of the dollar-per-barrel oil price.


Fourth, potential sources of project financing need to be considered as LNG projects are extremely expensive. Funding sources include Equity capital markets, Long-term Debt, ECA (Export Credit Agency)/Multi-Lateral, Commercial bank loans, Equipment financiers, Government funding and Trade players.

For PNG liquefied natural gas project in Papua New Guinea, operated by Exxon Mobil, $US5.5B is planned to be funded from equity contributions from the partners. Out of the remainder $US14B in project financing, $US8.3B will originate from ECAs, $US1.95B from uncovered commitments from a syndicate of 17 commercial banks, and $US3.75B as co-lending from ExxonMobil.

In the past, Japanese financial support has taken various forms such as Overseas Investment Loans, Untied Loans, Import Loans and Direct Loans. In certain cases Japan government has assisted through Overseas Government Cooperation Funds, credit guarantees from Japan National Oil Company, and investment and trade insurance from the Ministry of International Trade and Industry (MITI).

Environmental Impact

Fifth, risk to potential US export of LNG may arise from concerns over the environmental impact of frac jobs, over-supply of LNG, potential carbon tax imposition, wide-scale shale gas discovery in China (and Europe) and de-linkage from JCC indexation.

The US Environmental Protection Agency has proposed a new study to investigate the frac job process and determine whether drilling techniques pose a risk to drinking and underground water. A preliminary report is scheduled for release by the end of 2012, with a complete report to be published in 2014.

The fast ramp-up in LNG production in Qatar and Australia has the potential to create a LNG glut in global markets. Within the next five years Australian exports are planned to exceed 50 million tpa from current levels of less than 20 million tpa, ranking it just behind Qatar.

Figure 2
Figure 2: Pacific basin premium due to oil-index pricing [17]

Risks to US gas exports may also arise due to the incentives being offered to the drillers by the Chinese government [18]. In case China becomes self-sufficient in unconventional gas, it would reduce imports of LNG.

De-linkage of LNG prices from JCC may be detrimental to US gas export. In this regard, CERA energy executives (2011) have predicted that despite increasing influence of Western spot prices in short- to mid-term LNG contracts, longterm LNG contracts will continue to be linked to oil prices, perhaps with adjustments in the face of any ongoing gas glut.

Permitting delays and any postponement in constructing the liquefaction facilities on the Gulf coast may also lead to US losing out the LNG race to Australia, Qatar and Malaysia.


This preliminary study shows that conditions are opportune for the US to export LNG to Japan as well as Korea and China. The job creation prospects of such export and current US administration’s focus on low carbon fuels would definitely act as boosting factors for such export plans. Of course there are regulatory risks involved which could severely restrict shale gas production and derail hopes for export. Moreover, the liquefaction facilities on the Gulf of Mexico are yet to be financed and constructed. Export of large quantities of LNG from Russia, Qatar and Australia could be impediments as well.

Regardless, considering the fact that Japan, Korea and China would definitely diversify their source of energy supplies and are among the largest importers of LNG globally obviously means that US LNG can play a significant role in the Far East in the near future. Recent unfortunate incidents in the Japanese nuclear sector also point towards increased Japanese LNG import in the future. Finally, exporting attractively priced gas as LNG from the US will help undoubtedly support continued US domestic production, balance global market dynamics and offer global buyers a stable, attractively priced fuel supply alternative.

Mr. Das holds an MBA degree from the University of Chicago and an MS in engineering from the University of British Columbia in Canada. He has 13 years of experience in mining and energy.


[1] True, W.R., “2011 LNG World Trade”, Published in the Oil & Gas Journal, February 7, 2011.
[2] “International Energy Outlook 2010″, prepared by US Energy Information Administration,
[3] “Share of Total Primary Energy Supply in 2008 – Japan”, Published by IEA Energy Statistics. Refer to
[4] “Japanese utilities keen to import LNG from US to diversify sources”, Reuters, March 2, 2011.
[5] “Potential Supply of Natural Gas in the United States”, (December 31, 2008), published by the Potential Gas Agency, Colorado School of Mines, Golden, Colorado, 80401-1887.
[6] “Gas Production Statistics – Eagle Ford Information” published by the Rail Road Commission of Texas, March 30, 2011.
[7] “Economic Impact of the Eagle Ford Shale”, prepared by Center for Community and Business Research at the University of Texas at San Antonio Institute of Economic Development, February 2011.
[8] “North American Natural Gas”, lecture presented by Jay White, TransCanada, August 12, 2010.
[9] “Where are the $5 Gas Plays? Who’s profitable in this market?”, Hart Energy webinar, April 2009.
[10] “Review of Shale Economics”, By Anish Patel, Research Analyst Credit Suisse, June 2010.
[11] 131 FERC 61,037, United States of America, Federal Energy Regulatory Commission, Duke Energy Guadalupe Pipeline, Inc., Order of Hearing, Issued April 15, 2010.
[12] “Cheniere Appoints Bechtel to add Liquefaction Facilities at Sabine Pass LNG”, LNG World News, June 11, 2010.
[13] Gas Supply Potential and Development Costs of Rocky Mountain Gas and LNG Delivered to the Pacific NW, prepared by ICF International, Prepared for Jordan Cove Energy Project, L.P., 2008.
[14] Brito, D.L. and P.R. Hartley (2007). “Expectations and Evolving World Gas Market”, The Energy Journal 28 (1): 1-24.
[15] The Global Liquefied Natural Gas Market: Status and outlook, EIA Report #: DOE/EIA-0637, Release Date: December 2003.
[16] Natural Gas Week, June 21, 2010.
[17] Global Natural Gas Market Fundamentals, lecture presented by Darcel L. Hulse, President & CEO of Sempra LNG, July 19, 2010.
[18] “Oil & Gas Reality Check 2011″, Prepared by Deloitte Global Energy & Resources Group, page 10.

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