This paper looks at whether 23bn cfd of proposed US export projects, if permitted, would be tremendously disruptive to a supply system currently producing 66bn cfd. Would they exert upward pressure on domestic prices and thus ultimately undermine US competitiveness? It is excerpted from a 29 January presentation to the Washington LNG Forum-EPRINIC Embassy Series, co-hosted with the Embassy of the Russian Federation.

The initial question to ask is how much of 23bn cfd in proposed US exports is real and how rapidly might this might come on stream? There are a large number of North American projects seeking approval, but the LNG industry has always had far more proposed projects than will ever see the light of day.

Our database classifies the projects as follows: Operating Firm – has a final investment decision (FID); Probable – an FID is likely; Possible (scheduled) – efforts are far enough along that they have a proposed startup date; Possible (unscheduled) – much more speculative, often representing an idea that is floated to see if anyone is interested; and Remote – forget it.

By these definitions, the total probable and possible project global capacity as of the end of 2012 was 747mn tons of LNG or 2.7 times the industry’s installed capacity as of that date. At the average rate at which capacity has been added over the past decade, it would take 49 years to work them all off – and more are being added all the time. US LNG projects in the 48 states at 175mn tons represented 24% of the total proposed projects in the database, or 63% of the world’s total year end operating capacity. Canada accounted for another 7% and Alaska another 3% of the proposals.

Figure 1 shows the regional balance of projects and their classification. Clearly, a lot of projects in the database will not be built in the foreseeable future, if ever.

Since it takes at least four years from the FID to project startup, the capacity to meet demand through 2016 is already under construction: thus current FID decisions apply to 2017 and beyond. Meanwhile, the surge which Qatar put on the market in 2008-10, when coupled with the recession and the collapse of the US LNG market created a large surplus with severe price competition. One effect of these developments was that many of the projects which should have been approved in 2009-11 were not, creating the expectation of a nearer term tight market.

We have assumed that LNG demand out to 2025 will grow at the rate of 5%. The estimate is based on averaging four projected estimates of total world gas demand – Energy Information Administration (EIA), International Energy Agency (IEA), ExxonMobil and BP – and then applying a growing LNG share of the world gas market. We have also assumed a continuation of the following trends: that the imported gas share of world gas demand has been rising and that LNG has been taking a larger share of imports.


A two train greenfield project typically requires seven sales contracts. Most of these will be to buyers who will import the LNG into their own markets, but some will be newer “portfolio” contracts (self-contracting), in which the buyer assumes the debit service obligation but has the destination flexibility to sell wherever he can get the best return.

For example, of the recent contracts signed for exports from the US’ Sabine Pass, the BG contract is a portfolio contract and the rest are all the more typical fixed destination contracts. They will probably predominate for the other projects. Acquiring the necessary contracts will be a challenge, since most of the projects are being sponsored by companies without international LNG marketing experience. Thus, although the US’ Department of Energy might choose to approve a larger number of export permits, the competitive international market will prove to be a stern disciplinarian.


Much of the interest in US LNG is based on the huge disequilibrium between US commodity prices and European and Asian contract prices. For example, prices in 2012 were as follows: US Henry Hub, $2.74/mn BTU; Dutch TTF Hub, $9.26/mn BTU; Russian contract prices to Germany, $12.54/mn BTU; and Japanese LNG ex-ship as liquid, $16.66/mn BTU. Some of that difference is based on the different ways the Europeans and Asians calculate oil linkage, some is based on Northwestern European price competition with LNG and, for the Japanese, some on the disruptive effect of post-Fukushima nuclear replacement. But some of the difference is due to the high costs of transporting LNG to importing markets – a ‘basis differential’ – and should remain as long as LNG costs do not change.

Alone among the major LNG trading partners, North America has a truly gas-to-gas competitive commodity market. While the UK also has a competitive commodity market, it tends to be influenced by continental oil-linkage when LNG markets are tight. The ‘equilibrium’ pricing system thus might be based on Henry Hub pricing. And although it lacks the liquidity and transparency of Henry Hub, Qatar plays a similar ‘hub’ role in LNG, since it can arbitrage Atlantic Basin and Pacific Basin prices.

The pricing system might first see the export of US Gulf Coast prices to Europe. Then those prices might be netted back to Qatar where they would in turn establish Asian ‘equilibrium’ prices. The following figure is just such an estimate. The equilibrium differential between US and Europe is $5.21/mn BTU and between US and Japan $3.97/mn BTU ex-ship (before regasification). In this case $5.21/mn BTU of the total $6.52/mn BTU margin between the US (Henry Hub) and Europe (TTF – Title Transfer facility, a Netherlands-based virtual trading point for gas) represents the underlying transportation ‘basis differential.’ Only $1.31mn/BTU is the disequilibrium between the US’s fully competitive commodity market and Northwest Europe’s mixed commodity/contract market.


European price clauses typically link the price to a mix of oil products. One set of terms are known as ‘pass through factors,’ which divide the price changes between buyer and seller. Discounting is usually done by reducing the pass through factors.

Northeast Asia and China have largely adopted the Japanese approach to oil linkage. It utilizes a simple formula which is linked to the Japanese customs cleared price for crude oil – the Japanese Crude Cocktail or JCC. It is in the form of: P=C+S*JCC, where P is the price in $/mn BTU, C is a constant expressed in $/mn BTU and S is the ‘Slope,’ a dimensionless number. Discounting is most often done by changing the slope, although sometimes the constant as well.

The difference between the two markets is shown by the price relationships. In 2012, the TTF price was equivalent to 48% of Brent crude, while the Japanese price was 86% of Brent – and allowing for a regasification margin, it was probably 91% as gas.

Much of the difference between TTF and the Japanese price is due to the formulas themselves. Northwest Europe has benefited from the price competition that was unleashed by the LNG surge in 2009-10. LNG arbitrage together with North Sea commodity competition exported weak North American prices to the continent through the open access EU pipeline system; in 2008, TTF had been 68% of Brent. No similar price competition has been possible in Asia because there is no access to commodity gas. This has been a powerful driving force behind the Asian interest in US exports, since it gives Asia a source of gas-to-gas competitive commodity supply similar to that which has already benefited Europe.

The most common type of LNG contract is the delivery ex ship (DES) contract in which the seller delivers to the buyer’s receipt terminal and the price clause is based on destination market conditions. Less common is the free on board (FOB) contract. All of the US export contracts so far are FOB contracts, but they are unique in that their pricing clauses are based on origin pricing keyed to the North American commodity price at Henry Hub. Thus, unlike traditional clauses, the economic rent – and the price risk – goes to the buyer, not the seller. That is their appeal to oil-linked contract buyers.


There is a common view that present prices reflect surplus and are well below long-run marginal cost, and increasing exports will put further upward pressure on prices. Thus, there is certainly a significant supply price risk for any buyer. But prices in Northwest Europe – the ‘combat zone’ where North Sea pipelines and LNG terminals quickly transmit commodity price signals – are also volatile. This suggests that there is substantial price risk for both supply and demand for this part of Europe.

There is less risk in the European periphery, such as Spain, where competitive commodity gas is less available. And Asia, where competitive commodity gas is not available at all and competitive supply costs are high, remains a much less risky target market. Much of the new LNG for Asia is coming from Australia, where costs are proving to be very high. These have tended to put a floor on regional LNG offerings. China also has the option of pipeline supply from the Caspian and from Russia. But these pipelines are long and – assuming that the sellers are willing to take the same netback from China that they get from Europe – will also result in high delivered costs.


International LNG market competition is likely to place a significant limit on the amount of LNG the US will export. The concept that LNG exports might drive US gas prices up to the point where they threaten competitive energy prices ignores the substantial LNG transportation costs that will inevitably keep US LNG exporters’ prices below those of European or Asian LNG importers. Asia, with its current LNG contract pricing practices, is probably a better market than Europe, particularly since Asian competitive supply alternatives tend to be costly.

* James Jensen is an energy economist at consultancy Jensen Associates ([email protected]).