The US LNG export stampede: another gas revolution in the making

November 5, 2012 | 00:00

The US LNG export stampede: another gas revolution in the making

Thanks to the shale gas revolution, the United States - not long ago expected to become the world's largest importer of liquefied natural gas (LNG) - is on its way to becoming one of the world's largest LNG exporters, unless the US government intervenes to limit exports of cheap gas to its industrial competitors. But what we are seeing is not just another large wave of LNG supply of the kind we have seen from Qatar and are now witnessing from Australia. This new wave promises - or threatens, depending on your point of view - profound changes in the way that natural gas is traded and priced in markets across the world.

The United States is on its way to becoming one of the world's largest LNG exporters (c) Tribune

It promises to be the biggest U-turn in energy history. During the first half of the 2000s, billions of dollars were spent by developers of LNG regasification facilities as the United States resigned itself to a future of steadily declining natural gas production and turned to LNG imports to fill a looming supply-demand gap. Not only that: in countries around the world, developers of natural gas liquefaction projects were investing billions of dollars to be able to meet projected demand for LNG in the US. In Qatar, Yemen, Angola and elsewhere, the US was looking an increasingly attractive market.

Then came North America's unconventional gas revolution. This "shale gale" caused havoc with these plans and expectations. Developers of regasification facilities had to come to terms with the fact that their expensive new assets were going to be vastly under-utilised, while LNG export projects elsewhere were forced to look for new markets - in Asia, Europe, Latin America and the Middle East.

But that was not the end of the story. In August 2010, a company called Cheniere filed an application with the US Department of Energy (DOE) requesting approval to start exporting LNG from a proposed liquefaction plant to be located at its regasification facilities at Sabine Pass in Louisiana. This first application was for export to countries with which the US has a Free Trade Agreement (FTA). In these cases the DOE is obliged to grant approval because, as the law stands, such applications "are deemed to be in the public interest". However, few FTA countries are significant importers of LNG - the only major one being South Korea.

More significantly, the following month Cheniere applied for approval to export to non-FTA countries. This is a much higher hurdle. Before making a public interest decision, the DOE has to issue a Federal Register Notice of application seeking comments, protests and motions to intervene. To date, the only project to have been granted such an approval is Cheniere's Sabine Pass.


The company's rationale for building an export capability was simple. Because of the nature of LNG, liquefaction and regasification projects both need very large storage tanks and complex facilities, such as jetties and berths, to allow LNG ships to load and unload their cargoes. So converting an existing regasification facility into a liquefaction facility is much less costly than building a green-field project. If the US no longer needed much import capacity because it was awash with gas, why not construct a liquefaction plant at the site to allow two-way - export and import - operation?

"Why not indeed," thought other owners of idle regasification facilities. The consequence was that two years later, by August 2012, the DOE had received applications to export LNG to non-FTA countries from 9 proposed projects in the Lower 48 states (including Cheniere's Sabine Pass) for a total of 14.6 Bcf/d (billion cubic feet per day) of gas.

Since then the rush has become a stampede. The latest figures from the DOE show that the number of applications for LNG export to non-FTA countries has risen to 16 for a total of 23.7 Bcf/d of gas, as chart

If the US no longer needed much import capacity because it was awash with gas, why not construct a liquefaction plant at the site to allow two-way - export and import - operation?
1 shows. These are astonishing numbers. This volume of gas is equivalent to 245 Bcm/year (billion cubic metres per year), more than half the gas consumed in the European Union in 2011. To put it another way, it is equivalent to 180 million tonnes of LNG, which is three-quarters of the total global volume of LNG traded last year. And these numbers do not include the probable export of LNG from Canada and possible exports from Alaska.

Herd mentality

The causes of the US LNG export stampede are not hard to fathom. They are neatly summed up in chart 2 which shows the evolution of global gas prices from 2001 to 2011.

In around 2008, something odd started to happen to US natural production. Instead of continuing the long-term decline that conventional wisdom expected, it started to climb steeply as the unconventional gas revolution in North America started to make itself felt in a big way. By 2010 it was becoming clear that this was no overnight phenomenon. Gas prices in the United States had fallen sharply, making the US an unattractive market for LNG selling at prices linked to Henry Hub. Earlier this year the Henry Hub price fell briefly to below $2/MMBtu and today it struggles to get above $3.50/MMBtu.

As LNG destined for the North American market was backed out by rising indigenous production and falling gas prices, it began finding its way to other markets, notably Europe and Asia-Pacific.

Meanwhile, oil prices were rising steeply, dragging with them the price of gas in long-term contracts with oil-indexation clauses, such as the majority of pipeline gas contracts into Europe and LNG importation contracts into Asia-Pacific. In continental Europe, cheap LNG contributed to falling prices at trading hubs, notably the National Balancing Point (NBP) in the UK, but also the other increasingly liquid hubs in north-west Europe. Big gas buyers started to buy more gas directly from hubs and to insist on hub pricing from other suppliers when they could.

From around 2009, the German border price began to diverge from the Japan Imported LNG price, reflecting more spot gas imports into Germany and re-negotiation of oil-indexed long-term contracts. European importers were reducing their take under long-term contracts and buying cheaper spot gas.

It was this pressure that was encouraging producers to make temporary concessions to buyers and leading to contract re-negotiations - and indeed to some buyers seeking arbitration. Major wholesale buyers, such as E.ON and RWE, suffered large losses on their gas sales as they were forced to sell gas bought under long-term contracts at lower hub-based prices. Today, with Asia-Pacific sucking in large volumes of LNG, especially following the post-Fukushima nuclear crisis in Japan, hub prices in Europe have begun to converge with long-term contract prices.

In Asia, where most LNG contracts are linked to oil prices, gas prices rose steeply, averaging around $11/MMBtu in 2010 and more than $15/MMBtu today. It is the wide disparity between gas prices in the US and those in Asia-Pacific that has created the arbitrage opportunity that would-be LNG exporters in the US are seeking to exploit.

Can it last?

The big question, of course, is: "How long will this gas price divergence last?" Opinions differ, not surprisingly, but it looks likely that US gas prices will remain soft for the foreseeable future. Chart 3

The big question, of course, is: "How long will this gas price divergence last?"
shows the view of the US Energy Information Administration (EIA) as to how US gas production is likely to develop between now and 2035. It shows shale gas production continuing to rise sharply over the long term, more than compensating for the decline in conventional production. In the EIA's Reference Scenario, the average wellhead gas price in the Lower 48 states remains below $6/MMBtu (in 2010 $) until after 2030.

According to Shell's Chief Financial Officer Simon Henry, Shell - the largest LNG player of the international oil and gas companies - is currently planning around US gas prices of $4-6/MMBtu, on the basis that current prices are not sustainable and will need to rise above $4/MMBtu before too long, while prices above $6/MMBtu would cause electricity generators to switch back from gas to coal.

The view of Cheniere CEO Charif Souki - who as we have seen has been putting his money where his mouth is - is that LNG exports from the US have become "necessary to maintain balance in US energy markets". Speaking at a conference of LNG producers and consumers in Tokyo in September, he said that a key factor driving gas production in an already over-supplied market will be a drive to ramp up indigenous oil production. Souki believes that liquids production from "wet" shale plays will exceed 7 million b/d (barrels per day) by 2020, creating more than 12 Bcf/d of "costless" supply of associated natural gas.

Conversely, there appears to be little support among forecasters for a major fall in the price of oil over the medium to long term, so oil-linked gas contracts are likely to remain expensive for the foreseeable future unless their terms are re-negotiated to change the price-formation mechanisms.

Indeed over the past year we have started to see increasing frustration among senior utility executives and ministers in Japan, where the almost total closure of the nuclear industry post-Fukushima has boosted imports of expensive LNG, with a severe impact on the country's balance of payments. They have been describing having to pay oil-indexed gas prices as "absurd" and "not rational" in a world where Americans are paying so little for their gas.

Speaking volumes

A crucial question, then, is: "How much LNG are we likely to see exported from the US over the coming two decades?"

Chart 4 shows the results of analysis published in a special report (of which I was the lead author) in the September edition of the monthly journal LNG Business Review, published by Gas Strategies Group. The starting point was the DOE's August list of projects that had applied for approval to export to non-FTA countries.

In assessing which projects were likely to go ahead in each scenario a range of factors was taken into account. These included: the credibility, capability and track record of the project sponsors; how far the projects have advanced along the development process; the availability of sufficient feed gas; whether the sponsors have obtained purchase commitments from customers, and the firmness of such commitments; the business model being employed (for example, long-term contracts versus tolling); and how competitive the projects look compared with not just other US projects but also liquefaction projects under development elsewhere in the world.

Project competitiveness is crucial. As we have already noted, projects that are conversions of regasification facilities have a big advantage in that much of the necessary infrastructure will already be in place, especially when it comes to tanks and jetties. Sabine Pass, for example, already has five tanks and two berths (along with dedicated tugs) and so will need only one new tank and no more berths. This helps to explain why the two-train, 9 million tonne/year project is expected to cost just $5.6 billion, a specific capital cost of some $620/tonne/year (t/y) of capacity. This compares with up to $3,000/t/y for some of the new Australian projects, though costs there include upstream facilities that are not needed by US projects.

The business models being adopted by most US projects vary but generally gas price risk is being passed on to the buyers. Most of the proposed projects are looking to sign tolling agreements. For example, Cameron LNG has signed commercial development agreements with Mitsubishi Corporation, Mitsui & Co., Ltd. and GDF Suez, which include negotiation of three 20-year tolling agreements for 4 mtpa (million tonnes per annum). Freeport LNG has signed 20-year tolling agreements with Osaka Gas and Chubu Electric, each for 2.2 mtpa, covering the entire output of its first 4.4 mtpa train. It expects to sign similar agreements for the second and third train before the end of this year.

Note the involvement of several Japanese utilities and trading houses.

In April, Japanese trading house Sumitomo Corp and Tokyo Gas Company said they were holding talks with Dominion Resources for the right to buy LNG from the Cove Point project and that they had signed

"Considering the market situation and the circumstances of the pricing formation of crude oil, the oil-linked pricing mechanism is no longer rational"
a preliminary agreement for up to 2.3 million mtpa of capacity for 20 years from 2017. Dominion says it plans "to provide gas liquefaction and LNG export services to customers that will provide their own gas supply". The Japanese companies said they were considering sourcing gas from a Marcellus shale gas project in which Sumitomo is a participant. Other Japanese companies have also been taking positions in North American shale plays.

One exception to the tolling model is Cheniere's Sabine Pass project, which has signed 20-year sales and purchase agreements (SPAs) with BG Group (5.5 mtpa), Gas Natural (3.5 mtpa), Kogas (3.5 mtpa) and GAIL (3.5 mtpa). However, even these agreements are structured so that it is the buyers that take gas price risk.

The LNG Business Review chart shows that in a low-case scenario, exports begin in 2017 and ramp up to a plateau of just over 40 mtpa by 2023. In the base-case scenario, exports begin in 2016 and ramp up to a plateau of 56 mtpa by 2021. In the high-case scenario, exports begin in 2016 and ramp up to a plateau of 78 mtpa by 2022.

These scenarios have, however, been overtaken by the events of the past two months (as the LNG Business Review article predicted they would be). In particular, two highly credible projects have since applied for non-FTA approval from the DOE: Golden Pass, a 15.6 mtpa joint venture of Qatar Petroleum and ExxonMobil; and Corpus Christi, another Cheniere venture with a planned capacity of 15 mtpa. Re-running the analysis with these two projects included would significantly increase the plateau volumes in the base-case and high-case scenarios. The low-case scenario is not affected because it assumes that the US government imposes a limit on total LNG export volumes.

The Golden Pass project is particularly significant because of its shareholders. ExxonMobil has lots of
It is in the interests of Qatar to go ahead with Golden Pass as it would displace other US LNG exports - a case of "if you can't beat 'em, join 'em".
gas in the US and both it and Qatar Petroleum would have no trouble coming up with the required $10 billion investment. Qatar also controls a vast fleet of LNG ships. It is in the interests of Qatar to go ahead with Golden Pass as it would displace other US LNG exports - a case of "if you can't beat 'em, join 'em". It would also give the Qataris a lot of optionality.

Corpus Christi has the disadvantage of being a green-field project - most of the front-runners in the analysis were regasification conversions - but it has a highly credible sponsor in Cheniere, which has already embarked on the expensive and time-consuming process of seeking FERC approval for siting and construction. The accompanying map lists the projects that are seeking FERC approvals.

Together these two projects would push up the base-case plateau to around 87 mtpa or 120 Bcm/year (to compare: gas consumption in Germany in 2011 was about 73 Bcm/year). Interestingly, Cheniere's Charif Souki predicts that the US will be exporting 10-12 Bcf/d (75-90 mtpa) of natural gas from 4-6 LNG projects by the mid-2020s.

Note that Cheniere's Sabine Pass project, the only one under construction, will have a capacity of 18 mtpa, assuming that the second phase goes ahead as planned. Today, that volume alone would make the US the world's sixth-largest LNG exporter. Such is the scale of most of the front-runner projects that it would not take many to put the US in the top three - after Australia and Qatar - by the early 2020s.

Policy decision

The biggest constraint that other proposed projects face at the moment is a de facto moratorium imposed by the DOE on new non-FTA export approvals, while the likely economic consequences of

US policy-makers face an unenviable task in coming to a decision on whether to restrict LNG exports and, if so, at what level to set a cap
large-scale LNG exports are studied. A particular concern is the potential impact on the price of gas to US consumers. Earlier this year the EIA produced a report giving its view of the likely impacts, but the DOE is still waiting for a second report, the publication of which has been delayed several times. It is now expected to appear around the end of the year.

US policy-makers face an unenviable task in coming to a decision on whether to restrict LNG exports and, if so, at what level to set a cap - an issue seen by some as the most important energy policy decision in the US in recent memory. Whatever they decide is bound to upset a lot of people.

On one side of the debate there is a view that unfettered exports of LNG would lead to sharp rises in US gas prices, putting the brakes on an industrial renaissance that has been one of the welcome consequences of the unconventional gas revolution.

For example, Dow Chemical Company, which claims to have been "among the first manufacturing companies to declare a comprehensive plan to take advantage of the structural change in the natural gas market", believes that: "Natural gas represents a tremendous competitive advantage for American industry that must be nurtured. Actions that threaten to return natural gas prices to parity with global oil will jeopardise this once-in-a-lifetime opportunity."

On the other side of the debate are those who believe that the unconventional gas revolution has so changed the natural gas landscape that the US has more than enough gas to export substantial volumes of LNG without significantly affecting sustainable domestic gas prices (as opposed to the very low prices that have prevailed recently, which look unsustainable over the long term).

According to Cheniere's Charif Souki: “At almost every level of government in the US today there is a realisation that we are in a position to produce a lot more natural gas than we know what to do with. Most of the principal players have started to think about new ways of using natural gas. But they’re all very difficult to implement and take a long time to put in place. New production and new production capacity far outstrips new demand. So we’re sitting today on a significant amount of latent capacity to produce natural gas for which we have absolutely no market.”

To support his views, Souki points to studies conducted by Brookings Institute, MIT, Navigant Consultants and Deloitte. "Those studies have determined that - if we take it in a measured fashion - we can have a very significant ability to produce natural gas and export it, while taking care of all the domestic requirements, and without significantly affecting prices."

The Deloitte report mentioned by Souki looks in detail at the issue of how exports would affect domestic prices. It has used modelling techniques to examine what effect 6 Bcf/d of exports would have on prices over the long term (the 6 Bcf/d is made up of just three projects: Sabine Pass, Freeport and Lake Charles). The report comments: "The results show that the North American gas market is dynamic. If exports can be anticipated, and clearly they can with the public application process and long lead time needed to construct an LNG liquefaction plant, then producers, midstream players and consumers can act to mitigate the price impact. Producers will bring more supplies online, flows will be adjusted, and consumers will react to price change resulting from LNG exports."

Talking 'bout a revolution

Should the US become a major LNG exporter, based on its shale gas revolution, this will have major consequences for global gas markets.

First of all, because of their low relative capital cost, LNG export projects based on conversions of existing regasification facilities look very competitive with projects being planned elsewhere, notably Australia, but also Russia, east Africa, and the Mediterranean. US exports are unlikely to affect the Australian projects that have already taken final investment decision (FID), as these projects are generally underpinned by long-term oil-indexed contracts that have already been agreed. But the developers of new projects outside North America will be anxiously awaiting the decision of the US government as to whether to limit exports. And with the DOE report not being published until the end of year, and allowing for a period of public consultation following the report, a decision is not likely until well into 2013. Analysis conducted by Gas Strategies, an energy consultancy (and publisher of LNG Business Review), indicates that 40 mtpa of US exports could delay projects outside North America by up to three years. Exports of 80 mtpa would increase that to around 5 years.

More fundamental than the impact on US domestic prices or potential delays to planned liquefaction projects, is how large-scale LNG exports from the US - indeed even the possibility of such exports - is likely to affect the thinking and behaviour of gas industry players and policy-makers. There is the potential for US exports to change the way that LNG is contracted and traded in ways that are currently hard to predict.

Developments in the US have already led to increasing dissatisfaction among buyers in the crucial LNG markets of Asia with the price-formation mechanisms in long-term LNG contracts and the level of prices they generate.

Much of the growth forecast for LNG over the coming two decades will take place in the markets of Asia-Pacific - so there is a lot at stake. Last month at the Gastech conference in London, Shigeri Muraki, a senior executive at Tokyo Gas, Japan's largest gas utility and one of the world’s largest LNG buyers, told delegates: "The most critical issue for the future development of LNG markets in Japan and Asia is the pricing mechanism. LNG in Asia has been typically linked to crude oil. However, considering the market situation and the circumstances of the pricing formation of crude oil, the oil-linked pricing mechanism is no longer rational. We have started discussions to find new appropriate pricing mechanisms - mutually acceptable for sellers and buyers - considering the globalisation of LNG trade."

Politicians are also starting to make themselves heard. At the September LNG producer-consumer conference in Tokyo, Japan's trade minister, Yukio Edano, said: "With the paradigm shift due to full-
"To come up with a new method to replace oil-linked indexing is an agenda that both producers and consumers have to tackle to stabilise global LNG demand/supply"
fledged production of shale gas, oil-linked indexing is starting to be less reasonable. If new suppliers from North America, Russia and Africa enter Asian markets in a few years, it will no longer be reasonable. At current price levels, the use of coal and nuclear power has to rise, which would hurt LNG demand for a long time. To come up with a new method to replace oil-linked indexing is an agenda that both producers and consumers have to tackle to stabilise global LNG demand/supply."

Comments like these are not just a reaction to the prospect of large-scale LNG exports from the US, but this prospect is clearly an important driving factor. Cheap gas confined to the borders of North America is one thing; cheap gas with a credible future route to Asian markets is quite another.

European throes

So what does this all mean for Europe? It is clear that the pricing of natural gas has never been more controversial than it is today, because of a number of factors that include: stubbornly high oil prices; the effects of the shale gale on prices in North America; the globalising effects of growing LNG trade; the massive losses made in recent years by big European wholesalers; and the growing tensions over oil-linked pricing in Asia-Pacific.

In a book on the pricing of international gas just published by the Oxford Institute of Energy Studies, Professor Jonathan Stern writes: "The 2010s are likely to be a period of international gas price disequilibrium and uncertainty in many parts of the world: North America in relation to price level, Europe in relation to price formation, and CIS in relation to both price formation and price level. Asian LNG importers seem likely to maintain the JCC [Japan Crude Cocktail] price-formation mechanism through this decade, but not indefinitely, with short-term trading and pricing playing an increasing role."

Europe has been in the throes of a transition from mostly oil-linked pricing to pricing based on gas-on-gas competition - in other word, pricing based on gas trading hubs - for several years. That trend will continue as regulators and policy-makers push through policies to foster and integrate competitive liquid markets throughout the European Union. Stern believes that a wholesale move from oil-linkage to hub-based pricing in internationally traded gas is only a matter of time.

Large-scale exports of LNG from North America can only accelerate this trend.


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