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Calcasieu Pass adds to US LNG second wave

Venture Global takes the third Gulf Coast export FID of the year, even as questions over pricing grow

US LNG developer Venture Global sanctioned the final investment decision (FID) on its 10mn t/yr Calcasieu Pass LNG terminal in August, the third project to get greenlighted this year. And the Federal Energy Regulatory Commission (Ferc) has two other Gulf Coast projects with the status "under construction"—one that took FID in 2018 and one expected to do so imminently.

Calcasieu Pass joins Golden Pass LNG and Sabine Pass LNG Train 6 in the 2019 FID club. US LNG marketer Cheniere took FID on Corpus Christi Train 3 in May 2018, while Tellurian, a new entrant, is due to take FID on its 27.6mn t/yr Driftwood LNG project later this year. The five "under construction" projects add up to a hefty 63.1mn t/yr of additional capacity in the so-called ‘second wave' of US LNG export project slated to hit the market in the first half of the next decade.

Capacity cascade

If just over 63mn t/yr of capacity is not chunky enough, the scale of Gulf Coast export capacity classified in earlier stages of development in Ferc's project database quickly add up to some fairly staggering numbers. As shown in Fig1., six projects approved by Ferc, but not yet under construction, could contribute a further 63.7mn t/yr if they all moved ahead.

Add in the 6.67mn t/yr floating Delfin LNG project, which, due to its offshore location, is approved by the Maritime Administration of the US department of transportation, rather than Ferc, and the total approved new capacity is almost 133.5mn t/yr.

The six projects proposed to Ferc, with an approval application pending, add additional total capacity of 69mn t/yr, and the compound potential new Gulf Coast export capacity rises to 202.5mn t/yr.

A further six projects have been proposed to Ferc and are in pre-filing. Their combined 66.4mn t/yr of capacity would take the compound figure to just shy of 269mn t/yr.

It is highly unlikely all of these projects will come to fruition. And even achieving a significant proportion of them throws up a number of uncertainties—from the long-term sustainability of the resource base and infrastructure to move from wellhead to coastal liquefaction facility, through to congestion in the Glf's shipping lanes and the capacity of the global LNG shipping fleet, to the growth of gas demand to absorb the new production.

Pricing challenges

But a key short-term challenge is the pricing structure of US exports. The ‘first wave' of US liquefaction was based on developers passing through price risks to off-takers, the Henry Hub+ model, in part due to US LNG developers' lack of balance sheet strength, says Michael Stoppard, chief global gas strategist at consultancy IHS Markit.

This worked relatively well in a world where long-term buyers were comfortable to sign oil-linked contracts and the LNG market was tight. The liquidity of Henry Hub and of global crude benchmarks offered ample hedging opportunities to manage a disconnect between buying and selling on different bases, while portfolio players could trade non-contracted volumes in an LNG spot market well above depressed Henry Hub levels.

The current low LNG spot prices have acted as a sharp reminder to the portfolio players that Henry Hub-linked US exports are not necessarily at a huge discount to international prices, with bruising implications all too apparent in some ugly second quarter financial results. This has led to Asian buyers agitating for changes to their higher oil-indexed pricing.

New modes could emerge, but they are challenging. Europe may develop an increasing appetite for term LNG contract supply, as UK and Dutch domestic swing supply leaves northwest Europe increasingly dependent on just Norway and Russia and potentially less sanguine about simply just accessing the LNG spot market as a source of flexibility.

But most European utilities can only commit to contractual LNG supply on an index linked to European marker prices. "This is the only price our customers will accept", Andree Stracke, chief commercial officer at German utility RWE told a May conference.

No easy option

US project developers and off-takers could look to push the price risk onto the US producers, by offering to buy supply on a netback to the northwest European TTF benchmark. But this is also problematic given that many US gas producers tend to be relatively small and fragmented, says Stoppard. Neither smaller US producers or European utilities, largely still suffering economically from a slow reaction to the European pivot to renewables, can put their balance sheets "on the line" by agreeing to the others' preferred pricing index, leading to a "stalemate", he says.

Another option for potential off-takers trying to attract buyers would be to sell linked to a Gulf Coast LNG export price, which should in theory interact with destination markets in Europe and Asia and thus be a palatable option for the demand side.

But the current price delta between the US domestic Henry Hub (HH) benchmark and the Opis US Gulf Coast LNG free-on-board (Fob) price is insufficient to make money, says Stoppard, warning this is likely to persist for much of the next two years.

Any potential off-taker willing to sell on a Gulf Coast Fob price-linked basis must bet that the differential will widen between now and the time of future deliveries, says Stoppard. This is mainly large aggregators and deep-pocketed traders, so finding the off-takers crucial to greenlighting projects has become more difficult.

Integrated approach

An alternative model has been proposed, says Stoppard—an integrated model which includes upstream assets and delivery pipelines. "This is somewhat counter-intuitive since the textbooks suggest the advantage of vertical integration erode in a commoditised marketplace [such as the global LNG market]," says Stoppard.

But an integrated project has similarities to a fixed price contract, as gas is delivered at cost, although there are risks around keeping costs stable, particularly in a high opex environment like the Permian.

The advantage of this model, says Stoppard, is that it may give access to a low-cost project out of the Permian which is robust to low LNG netbacks—more so than a Henry Hub+ structure. The rise of ever greater low-cost and stranded volumes of associated gas out of the Permian have given a strong boost to the integrated model, he continues.

However, the capex hurdle and complexity are significantly greater, meaning that the potential number of investors are limited—with a focus again on aggregators and other companies with deep pockets. Moreover, Stoppard cautions, players may incur a "regret cost" if the return from the US domestic market is greater than the return from the netback received from LNG sales after all the additional capex has been spent.

In effect, why risk spending money on pipes and liquefaction if you can simply sell profitably into the US market? The integrated model—for all its appeal—is still to receive market validation through a wide roster of commitments and investors, says Stoppard.

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