Introduction

Despite my prediction of low natural gas prices for 2015, we have made it clear that we are bullish on the long-term future of the U.S. natural gas market. There are a number of drivers that have been discussed in previous articles: Regulations by the Environmental Protection Agency (EPA) to phase out coal, a renaissance of U.S. chemical manufacturing that will increase natural gas demand, and the opening of new liquefied natural gas (LNG) export terminals in the U.S.

Today I want to discuss the global LNG market in detail.

LNG Technical and Economic Overview

To review, natural gas is predominantly methane, which is the simplest hydrocarbon. At typical temperatures and pressures, methane is a gas. Compressed natural gas (CNG) is methane that has been pressurized and put in a tank. LNG is natural gas that has been cooled to below -261°F, at which point it becomes a liquid. The advantage of LNG over CNG is that the liquid form takes up much less space, hence more can be transported in a given volume. A container of given size that could transport 1 unit of natural gas could transport 250 units of CNG, or 600 units of LNG. Thus, LNG is all about increasing the energy density of the fuel for more economical shipping.

Once LNG is produced it requires shipment on special ships that keep the LNG liquid during transport, and then conversion back into a gas at the destination. The LNG export market is driven by the differentials between the cost of producing and shipping LNG and the price of LNG at destinations in Asia and Europe. A recent report by BG Group (London: BG) shows how these differentials have shifted over the past year:


Source: BG Group, Global LNG Market Outlook 2014-15

In the graphic, “HH” refers to the Henry Hub price of natural gas, the reference for natural gas futures on the New York Mercantile Exchange (NYMEX). It is a good indicator of natural gas prices in the U.S. “NBP” is the National Balancing Point, the reference price for natural gas futures in Europe. “JCC” (Japanese Crude Cocktail) is a benchmark crude for Asia, much like WTI in the U.S. or Brent in Europe.

I have seen several independent estimates that have put the cost of liquefying, shipping and regasifying natural gas in the range of $2 to $3 per million British thermal units (MMBtu). Add this to the cost of producing the natural gas and transporting it to the liquefaction plant, and you have the breakeven cost for LNG. Production cost varies a lot depending on the location, but there are a number of operators who report breakeven costs below $2/MMBtu in the Marcellus Shale, presently the largest source of natural gas in the U.S.

Over the past five years, Henry Hub gas prices averaged $3.85/MMBtu. LNG spot prices in Asia, on the other hand, averaged $13.70/MMBtu, a differential of $9.85/MMBtu. Subtract out $3/MMBtu for liquefaction and shipping, and the potential margin of $6.85/MMBtu is three to four times the margin for gas sold and used in the U.S. The European market has been less lucrative, with LNG averaging about $4.50/MMBtu less than in Asia, but shipping costs from the U.S. to Europe are lower. Thus, margins for U.S. LNG sold in Europe — based on the past five years of pricing — would be in the $2.50-$3/MMBtu range.

These differentials explain the rush to build LNG export terminals in the U.S. But note on the pricing chart above what has happened to the Asia spot price for LNG through February. The price fell steeply for most of 2014, and after a brief rally near the end of the year resumed its decline. Henry Hub natural gas, on the other hand, held up much better, even though the price has declined this winter. As a result, the huge differentials between the U.S. and Asian markets that caused so many to line up for LNG export licenses have vanished.

After accounting for expected liquefaction and shipping costs, a small differential still exists. However, these export terminals are huge, multibillion dollar projects. There isn’t nearly as much room for cost overruns based on current projected margins, so the rush to build new terminals will probably slow for now.

Understanding the Global LNG Market

But the real question is whether the current situation is an outlier. To get a better handle on that, it may help to understand the global LNG market. The following overview was obtained and the data cross-checked primarily from three sources: 1) The 2014 BP Statistical Review of World Energy; 2) A January 2014 report from the Canadian Association of Petroleum Producers called An Overview of the World LNG Market and Canada’s Potential for Exports of LNG; and, 3) The recently published (and aforementioned) Global LNG Market Outlook 2014-15 from the BG Group.

Units have been converted into billion cubic feet per day (Bcf/d). For reference, there are approximately 1,025 BTUs in a cubic foot of natural gas, so one billion cubic feet of natural gas would be worth (1.0×109*1,025*$3.00/1.0×106) = $3.08 million if natural gas is priced at $3/MMBtu.

Total LNG exports in 2014 amounted to 32 Bcf/d. For perspective, U.S. natural gas production in 2014 was just over 70 Bcf/d, the most of any country in the world. The world’s largest LNG importer is Japan, which imported 11.7 Bcf/d in 2014 (37% of the world’s LNG imports). In second place was South Korea, which imported 4.9 Bcf/d in 2014, a decline of 7% from 2013 largely based on mild weather. China was in third place with 2.6 Bcf/d of imports, while India was fourth with 2 Bcf/d of imports. In total, 28 countries imported LNG in 2014, and Asia accounted for 75% of all imports.

Outside of Asia, the largest LNG import market was Europe, led by Spain’s 1.4 Bcf/d and the UK’s 1 Bcf/d. The fastest growing LNG import market was in Brazil, where a drought has reduced available hydropower and resulted in a 25% year-over-year increase in LNG imports. The UK’s 17% year-over-year gain made it the second fastest growing market in 2014, just ahead of China and India.

On the export side, Qatar is by far the world leader with 10.4 Bcf/d of exports, 32.5% of the world’s LNG export total. Indonesia’s 2.2 Bcf/d of LNG exports was good for second place, while Trinidad and Tobago (1.9 Bcf/d), Algeria (1.6 Bcf/d) and Russia (1.4 Bcf/d) rounded out the top five. In total, 19 countries exported LNG in 2014.    

Six new import terminals began operating in 2014 with a total nameplate capacity of 3 Bcf/d, with Lithuania becoming the 28th and most recent importer. The other new terminals were all located in Asia. Japan, South Korea, and Indonesia added one terminal each, and China two. China now has 13 terminals in operation and three more under construction.

LNG production in 2014 was at about 85% of nameplate capacity. Papua New Guinea became the 19th nation to export LNG. 2014 also saw the first cargo from the QCLNG project in Eastern Australia, which is the first large-scale coal-bed methane to LNG project. One expansion train at Arzew, Algeria also started production. Algeria and Nigeria both saw improved LNG production in 2014 relative to 2013.

Final Investment Decisions (FIDs) were made in 2014 on three projects representing 3.3 Bcf/d of capacity. These projects consisted of five new trains in the US (Freeport LNG and Cameron LNG) and one floating LNG (FLNG) unit in Malaysia. These projects are expected to come online in 2020.

Late this year the first LNG cargos could leave continental U.S. if Cheniere Energy (NYSE: LNG) brings its Sabine Pass LNG project in the Gulf of Mexico online on schedule. (There is a small amount of LNG exported primarily to Japan from a ConocoPhillips (NYSE: COP) LNG plant in Kenai, Alaska, that has been in operation for over 40 years). A total of 9.2 Bcf/d of export capacity has been approved in the U.S. by the Federal Energy Regulatory Commission (FEC) and is currently under construction.

Another wave of new LNG supply is also expected to come from Australia, which currently has 12 trains and 1 FLNG unit currently under construction. These projects are expected to add a total of 7.6 Bcf/d of supply capacity by 2019. Globally, 26 trains and 4 FLNG units are under significant construction for a total of 16 Bcf/d of new supply capacity by 2020. Given its proximity to key Asian markets Australia will likely be the most serious competitor for U.S. LNG exporters.

The big question marks in the years ahead are whether slower Asian growth in 2014 was an anomaly or the beginning of a trend. The biggest factors influencing this will be the strength of China’s economy and the extent to which Japan resumes its nuclear power program, which has been sidelined since the Fukushima Daiichi nuclear disaster in 2011.

The next five years look like a period of significant LNG supply growth. The rate of increase in supply looks likely to outpace the rate of demand growth, which marks a change from recent years. However, the current pricing environment also makes it likely that some of these projects that are in the early planning stages will be canceled. In fact, Shell’s global LNG manager recently said that he expects only 15 to 20% of the projects approved by the Canadian government will be built over the next decade.

The real key for prospective LNG exporters will be to secure long-term offtake agreements at attractive prices. This has thus far been the case with the early wave of U.S. producers. Should the soft market conditions persist, this first wave of LNG construction in the U.S. may be the only significant wave for quite some time.

Conclusions

Our bullishness on natural gas is a result of multiple demand catalysts. This provides some measure of assurance that should one of these falter, there will still be enough impetus from the others to ensure demand growth.

For instance, in a previous article — Cheap U.S. Gas Fuels Chemicals Romance — I noted that projected demand from chemical manufacturing expansions was projected to increase overall U.S. demand for natural gas by 20% to 30%. With the electric utility sector expected to increase its consumption of natural gas as coal is phased out, and with the build-out of LNG terminals, we still have sufficient reason to expect that the long-term bullish case for natural gas remains. The potential softening of the global LNG market and its subsequent impact on natural gas demand only slightly weakens that case.  

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