Liquefied natural gas (LNG) export capacity planned in times of booming demand and higher gas prices is still coming on-stream despite much less favourable market conditions now. Global capacity is forecast to rise by up to 18 bn cfd over the next five years: equivalent to about half the entire global LNG trade during 2015. Demand growth over that period is expected to be less than 5% a year, giving a projected increase of 9 bn cfd at most by 2020, which should keep LNG prices under downward pressure for much of the period.

Faced with this scenario, many gas producers are beginning to rethink their plans. A number of strategies are under consideration, including postponing or even cancelling some projects. Some producers have proposed the establishment of some sort of gas cartel on the lines of OPEC, while others look set to try and protect or even increase their sales by improving the terms on which they supply their gas, for example by offering more flexible arrangements on volumes and prices. In the end, though, there may be no other way of dealing with weak demand and rising supplies other than by cutting prices.

LNG Exports

Too many LNG projects

A number of projects are scheduled to come on-stream between 2016 and 2020. Many of these are accounted for by Australia, the US and Russia; but others have also been proposed for Africa, Latin America, Iran, Canada, Papua New Guinea and Indonesia. Some of these will end up being postponed: others are likely to be cancelled altogether as falling gas prices cause capital spending to be cut.

High on the list of new projects between now and the end of the decade is Australia with six, totalling 5.9 bn cfd of new capacity. The first of these is Chevron’s Gorgon project, off Western Australia, which exported its first cargo in March. Also due on-stream this year are additional export trains at two projects that began operating in 2015, at Gladstone and Australia Pacific in Queensland, while next year new terminals will be commissioned at Wheatstone, Prelude and Ichthys, serving fields off the western and northern coasts.

Australia: LNG Projects, 2016-2017
Project Capacity (bn cfd) On-stream
Gorgon 2.1 2016
Gladstone LNG 0.5 2016
Australia Pacific LNG 0.5 2016
Ichthys 1.2 2017
Prelude 0.5 2017
Wheatstone 1.2 2017
Total 5.9

The projects currently planned for Australia account for nearly a third of the projected global increase of 18 bn cfd in LNG export capacity between now and 2020, and almost two-thirds of the likely increase in actual demand. When added to the country’s existing capacity they will give Australia a total of 11.3 bn cfd by the end of the decade, which could enable it to overtake Qatar to become the world’s largest exporter of LNG.

The six projects above are not the only ones proposed for Australia. Among those that have been proposed are new terminals for existing field developments, as well as for new and yet undeveloped offshore reserves. Low gas prices and weak global demand have led to the postponement or cancellation of some of the projects and others are likely to encounter the same fate. Some projects now in operation are already running at a loss under present market conditions.

Australia’s LNG projects will have to find new markets. At present, Australian exporters are dependent on Japan for about 80% of their sales. There is little scope for any increase for Australia or any other LNG supplier, as Japanese imports have fallen since 2014 and are forecast to go on decreasing, as nuclear power stations are slowly brought back on-stream after their closure following the tsunami of March 2011, which damaged the reactor at Fukushima. There are also plans for more electricity generation from renewable sources, and there is even the possibility of an increase in the coal-burn [1]. There could therefore be a decrease of about 1 bn cfd in Japanese LNG demand between now and 2020.

Australia’s exporters are actively seeking new markets elsewhere in Asia, including China and India. In the longer term, there may be new export opportunities in Asia, including Indonesia and Vietnam. These markets will be the target of other exporters, including Russia and the US, which also have ambitious plans to export more LNG.

Russian ambitions

Russia is planning even more new LNG capacity than in Australia, although uncertainty surrounds most projects and nearly all those that may still be regarded as firm are subject to delay: in some cases by a number of years. Russian export schemes are largely resource-led rather than market-led. Large untapped reserves of gas exist in the Arctic and in the east of the country, and the government is following the example of its Soviet predecessors by trying to exploit them as rapidly as it can.

In 2013, Moscow provided a further accelerant to their exploitation by ending Gazprom’s monopoly on LNG exports and allowing two competitors in the form of Rosneft and Novatek to build and operate LNG terminals. This not only led to new plans from the two newcomers, but also appears to have prompted Gazprom to draw-up proposals for new export schemes in what looks like an attempt by the Russian giant to ensure it remains the dominant force in the country’s gas industry. By doing so, however, it has almost certainly become over-stretched, making it difficult to pursue several new LNG schemes in addition to its other ambitious plans, which include the building of new export pipelines and expanding internationally, as well as defending its share of the domestic market where it is also experiencing competition from rival independent gas producers.

Access to finance is a particular problem: not only for Gazprom but also for its two LNG rivals, Rosneft and Novatek. Growing US hostility–supported by the EU–to the government of President Vladimir Putin has led to financial and other sanctions involving some large-scale energy developments [2]. While there is no outright ban on western involvement in energy developments, the deterioration in east–west relations creates a climate of uncertainty for potential western investors. Moreover, the EU Commission’s repeatedly stated aim of reducing the EU’s dependence on Russian gas means that Russia needs to spend heavily on new infrastructure such as pipelines to divert some of its gas away from Western Europe to new markets in Asia.

Low gas prices and difficulties over the financing of LNG projects mean that Russia is unlikely to have many of the schemes listed in below in service before 2020. The most likely outcome is for just three of them to be in operation by that date: those proposed by Novatek for Yamal, with a total capacity of 2.2 bn cfd. Rosneft’s two schemes look less likely by that date and Gazprom has other projects demanding its attention. The company is seeking finance for many of its schemes, particularly in Asia, where it has recently been able to arrange a five-year €2 bn loan facility with the Bank of China, but China’s main interest in imports of Russian gas appears to be in the construction of new pipeline connections rather than importing it as LNG.

Russia: LNG Projects, 2017-2030
Operator Scheme Capacity (bn cfd) On-stream
Gazprom Baltic 1.3 2021
Gazprom Sakhalin 3 0.7 2021
Gazprom Murmansk 1.6 Shelved
Gazprom Shtokman 1.0 Shelved
Gazprom Vladivostok Phase I 0.7 Delayed
Gazprom Vladivostok Phase II 0.7 Delayed
Total Gazprom 5.8
Novatek Yamal I 0.7 2017
Novatek Yamal II 0.7 2018
Novatek Yamal III 0.7 2019
Novatek Gydan 2.0-2.2 2018-25
Total Novatek 4.1-4.3
Rosneft Pechora Phase I 0.3 2018
Rosneft Pechora Phase II 0.2 TBD
Rosneft Sakhalin 0.7 After 2020
Total Rosneft 1.2
Total Russia 11.2-11.4

There are at present proposals for eight large LNG export schemes in Russia in a variety of locations in either the north or east of the country, amounting to up to 11.4 bn cfd of new capacity. The first of these is due on-stream in 2017, with others scheduled over the following four years. Many, however, remain uncertain and may not begin operation until well into the next decade–if at all.

Russian LNG terminals
Russian LNG terminals

New US phase for NG

Asia is likely to be the prime target for Russia’s additional LNG exports. It may, however, find that the Americans have got in first. The first of a new wave of US export terminals began operating in early-2016 with the commissioning of the first phase of Cheniere Energy’s Sabine Pass terminal on the Gulf Coast, the first of a series of LNG facilities designed to enable the US to export more than 10 bn cfd by 2020 .

A further 2.2 bn cfd of capacity could be available in 2020, or shortly afterwards. There are, however, a further 22 proposals, amounting to almost 29 bn cfd of new capacity. Eighteen of these schemes are proposed for the Gulf Coast. Given the large number of proposals for export terminals elsewhere in the world, most of these are unlikely to go ahead.

Australia, Russia and the US are by no means alone in planning new LNG exporting capacity. Proposals cover a number of other countries across several continents. In Africa, there are plans for terminals in Angola, Cameroon, Libya, Mozambique and Nigeria. In the Western Hemisphere outside the US, proposals exist for terminals in Bolivia, Brazil, Canada, Colombia, Trinidad and Venezuela, while in Asia plans exist for new export capacity in Brunei, Indonesia and Malaysia. Papua New Guinea’s exports look set to grow, requiring new terminal capacity; and Iran has ambitious plans to begin exporting LNG from its South Pars field-complex now that many sanctions on trade and investment have been lifted [3].

US LNG Terminals
US LNG Terminals

Expanding canal…expanding market?

After delays, strikes, and cost overruns, the Panama Canal expansion is finally set to open fully in 2016. But the global energy landscape has changed in the eight years since construction began, with opportunities first expanding and now, potentially, contracting. The question today is whether the new canal can still fulfil a promise to transform global LNG trade.

When Panamanians approved the expansion project by national referendum in 2007, planners could not have predicted the impact of the shale revolution on the production of natural gas in the United States, nor the potential for the Panama Canal to play such an important role in creating a global LNG market. By doubling the waterway’s capacity, the new canal will be able accommodate over 88 percent of the world’s LNG fleet, up from just 8.6 percent today.

Despite these challenges, there is still enormous potential for the Panama Canal – and for Panama’s economy. The trip from the U.S. Gulf Coast to Asia is 11 days shorter via the Panama Canal, resulting in significant cost savings from fuel to personnel. A lower natural gas price in Asia will eat into profits but the market remains worthwhile.

There are also regional benefits. The journey from Trinidad to Quintero, Chile will be 6.3 days shorter via the Panama Canal than the Strait of Magellan. Chile’s growing economy relies on LNG imports to meet its energy needs. Panama has also set its sights on transforming global shipping in other ways. As more stringent emissions controls come into effect, the global shipping industry is making a transition from fuel oil and diesel to natural gas. Canal authorities are considering the construction of an LNG receiving terminal and bunkering facilities for transiting ships.

Beyond LNG, the new Panama Canal is unlikely to have that much impact on the global oil market. The expanded canal will be able to accommodate tankers carrying 400,000 – 680,000 barrels of crude but that is much smaller than the majority of crude shipments. The only taker is likely to be Venezuela, which sends around 300,000 barrels of oil per day to China. Most petroleum is shipped on very large crude carriers (VLCC), which will exceed the draft limit of the new Canal.

Panama Canal costs (

Who will buy the gas?

Many LNG export plans were drawn-up about four or five years ago when gas prices were much higher. In 2012, for example, Japanese buyers were paying almost $17 per mn BTU. Today, spot cargoes are available at half that price. If prices remain close to current levels for any length of time, they will make many LNG schemes uneconomic. US LNG needs a price of about $10 per mn BTU to break-even. In Russia, the figure is probably close to $15 and in Australia, around $17 per mn BTU. This should ensure the cancellation–or, at least, postponement–of many projects. Most of Russia’s live projects are at least a year behind their original schedules already. The rising construction costs of LNG facilities provide a further disincentive to adding capacity. Australia’s newest project, Gorgon, has come-in a reported 46% over-budget and behind schedule.

After these considerations, there is still likely to be considerable overcapacity for LNG exports for a number of years and markets will become increasingly difficult to find. The focus of attention for most new exporters will be Asia, but opportunities there are likely to be limited. Japan–the largest LNG market–now appears to be in decline and there may not be much scope for increasing exports to South Korea and Taiwan, either, leaving China and India as the only large growth markets. LNG demand may not grow as quickly as anticipated as both countries increase the use of nuclear power and coal [4]. China also plans to extract gas from coal-seams in order to keep down the rise in imports [5].

The growth in China’s demand for LNG may yet prove to be higher than forecast by the most pessimistic forecasts, but not all exporters will necessarily benefit. Short haul suppliers, such as Australia and Papua New Guinea, will probably benefit the most. US export plans have relied heavily on Asian markets, including China, but US exporters could well find themselves at a disadvantage compared with Australia and other nearby suppliers.

There could nevertheless be new markets outside Asia, especially in gas-short countries in the Middle East, including Jordan, Lebanon and, ultimately, Syria, along with Kuwait and Egypt [6]. Another incremental market could be Europe, which has spare capacity available in its existing LNG import terminals and may be receptive to the idea of taking more LNG where countries wish to reduce their reliance on Russian gas for political reasons (see above).

It all depends on the price

The ability of LNG exporters to find markets for their gas will depend to a considerable extent on their flexibility when it comes to delivery terms: not only in terms of price but also on volumes, for example in terms of take-or-pay provisions in supply agreements. On the other hand, exporters need a certain level of prices in order for their LNG operations to be profitable: a level rather higher than exists in global spot markets at present.

From time to time, some exporting countries have looked for ways of controlling supplies in order to prevent prices from falling to sub-economic levels. The idea was floated as long ago as 2007 by Russia for a group of gas producers to cooperate in restricting supplies in the way that OPEC once did in order to raise oil prices. In recent years, however, the idea of a ‘Gaspec’ has begun to be seen as unworkable. Most gas is sold under long-term supply agreements, which could not function properly if production levels were to be adjusted downwards (or upwards) at the whim of some gas cartel. There is also the well-founded fear amongst gas producers of pricing themselves out of markets by artificially manipulating prices through cuts in production.

A better way to maximize returns in an oversupplied market might be for producers to focus on cost cutting throughout the supply chain, for example by using cheaper floating LNG terminals, as some companies are thinking about for some gasfields in Africa and elsewhere. Producers can also tie-up markets in consuming countries by investing in receiving terminals there, including floating terminals, as is being proposed for the Philippines. In this way, markets could be opened-up in countries that do not at present import any LNG. Global markets will nevertheless be slow to clear and LNG exporters may still have to endure a few more years of low prices and poor returns.

  1. Gas and Power: Japan to switch back to coal? Oil and Energy Trends 2014; 39:3; pp 7–8, DOI:10.1111/oet.12141.
  2. Looking Ahead: Russia considers response to Western sanctions; Oil and Energy Trends 2014; 39:5; pp 18–19, DOI: 10.1111/oet.12159.
  3. Gas and Power: Iran plans more gas production and exports as sanctions are lifted; Oil and Energy Trends 2016; 41:2; pp 7–8, DOI: 10.1111/oet.12351.
  4. Gas and Power: Burning of coal set to rise despite UN pledges to cut carbon emissions; Oil and Energy Trends 2016; 41:1; pp 7–8, DOI: 10.1111/oet.12344.
  5. Gas and Power: Asia looks to coal to augment gas supplies; Oil and Energy Trends 2014; 39:12; pp 8–9, DOI: 10.1111/oet.11210.
  6. Gas and Power: Egypt’s new gas field could hasten development of stalled fields of Levant; Oil and Energy Trends 2016; 41:3; pp 7-8, DOI: 10.1111/oet.12358.


  1. Thank you for sharing this article. I am surprised Japan will reduce their LNG import and turn into coal as energy supply. I am chemical engineer from Indonesia. Indonesia government has forecast that Indonesia will import LNG in 2019. Maybe the LNG will be imported from Singapore (most likely) because Singapore built LNG export terminal. I also think maybe Indonesia will also import LNG from Australia, if Australia is seeking for LNG markets.

I'd love to hear what your thoughts are...please feel free to leave a reply

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