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LONDON, Sept 5 (Reuters) – The United States is set to grab the first and biggest chunk of unfilled extra Asian demand for shipped gas between now and 2025 with help from a widened Panama Canal and prices that rivals could struggle to match.
A surge in U.S. natural gas production thanks to the shale revolution means proposed new liquefied natural gas (LNG) projects in Australia, East Africa, Canada and Russia can no longer count on exporting to the United States and will now have to focus more on sales to Asia.
Now, the distance to ship U.S. LNG from the Gulf of Mexico to Asia is set to be fall to about 9,000 miles from 16,000 after expansion work makes the Panama Canal big enough for LNG tankers.
That will allow U.S. exporters to compete for that same Asian market, transforming the United States from export destination to growth supplier for Japan, South Korea and eastern China in only a few years.
The Gulf of Mexico coast has tailor-made ports, storage and pipes it has used for LNG imports. It is part of the world’s biggest natural gas market and has specialist local labour available.
This gives LNG projects there a set of ‘brownfield’ advantages over ‘greenfield’ rivals off the undeveloped coasts of Mozambique and Tanzania, in the harsh Russian Arctic, and in remoter parts of Australia and Canada.
Political risk is also seen as relatively low – at least for the next few years.
Together, these factors should give the United States about a third of the 150 million tonnes per year (mtpa) of extra LNG demand expected between now and 2025 that is not already accounted for by about 100 mtpa of Australian supply currently under construction, according to analysts’ estimates. ()
“The cost stacks to Asia from the five major supply options end up in a very similar range… but the U.S. brings a unique proposition, and so might be getting a lion’s share of that extra demand,” said Asish Mohanty, senior analyst on North American LNG for Wood Mackenzie in Houston.
“We expect around 45 to 50 million tonnes a year of U.S. exports – all starting up before 2020 – with the rest to be shared amongst the others.”
Hesitation by those other LNG producers looks set to play into U.S. hands, too.
The last big non-U.S. LNG project to get the all-important Final Investment Decision (FID) from its backers was Japanese group Inpex’s Ichthys plant in Australia’s Northern Territory in early 2012.
Since then, only U.S. projects, namely Sabine Pass phases 1 and 2 in Louisiana, have won FID.
LNG exports are politically controversial in the United States because cheap gas has revived the economy, but the government approved a third export permit on Aug 7 in a sign that producers hurt by a glut and weak prices are winning traction in the debate as federal authorities grant permission for exports to countries such as Japan and China.
Production from shale formations using hydraulic fracturing and horizontal drilling techniques has sent the Henry Hub U.S. gas benchmark price below $3 per million British thermal units (mmBtu).
At the same time, Asian buyers have to pay up to $20 on the spot market and up to $17-$18 on long-term contracts linked to the price of crude oil. U.S shippers just have to come in under that, and many in the market believe they can.
Escalating costs have also slowed development of non-U.S. greenfield projects. The budget for Chevron’s half-built 15 mtpa Gorgon project has ballooned by about $15 billion to over $50 billion.
A third factor has been the sheer number of projects proposed worldwide in recent years – some 631 mtpa worldwide according to analysts at IHS CERA – which is more than four times the predicted need up to 2025.
“It’s a bit like being in a restaurant with a big menu,” said Washington-based IHS CERA analyst Eliza Notides Young. “This entrance of the U.S… just adds a whole new dynamic to the market.
“I think a lot of buyers are waiting to see what that might mean for projects in other regions and whether there’s room for price negotiations.”
Adding to uncertainty for non-U.S. projects is the widening of the Panama Canal and the cost reduction that will bring for U.S. LNG exporters.
Only 21 of the existing global fleet of 370 LNG tankers can currently squeeze through the Panama Canal, and none of them try. Yet more than 80 percent will be able to make the passage once widening is complete, according to LNG shipping consultancy Platou.
Delays have beset the widening project but it is currently expected to be completed by the end of 2015 – just in time for the first scheduled exports from Sabine Pass on the border between Texas and Louisiana.
IHS CERA estimates the shortened passage to Japan could shave $1.50 per mmBtu off the cost.
It puts the as-yet unknown canal charge at around 30 cents per mmBtu based on a $1 million round-trip fee for a medium-sized LNG tanker.
That still leaves a clear $1.20 saving per mmBtu – almost 10 percent of the direct ex-ship (DES) cost based on an estimate by shipper BG Group Plc.
BG, which is contracted to take 5.5 mtpa from Sabine Pass, puts the DES shipping cost to Asia at $11.20 per mmBtu via Panama.
BREAK THE OIL LINK?
There is a pricing game changer happening, too.
U.S projects can avoid the pricing model that forces buyers into 20-year contracts based on oil prices – so-called take-or-pay funding.
As was the case with shale production itself, it is the pre-existing infrastructure that has made the United States home to this revolution.
Greenfield projects like Gorgon in Western Australia are so huge and costly that only the biggest companies – Chevron, Royal Dutch/Shell, Exxon Mobil and a few others – attempt them.
They have to compete for capital with oil projects, so to get FID, they need that take-or-pay funding.
Building the liquefaction plant absorbs the majority of any LNG project’s budget but thanks to its other cost advantages, Cheniere Energy’s Sabine Pass and others like it can base pricing on cheap U.S. gas instead of costly global oil.
“That makes the project more likely to happen – and buyers like that,” said IHS-CERA’s Notides Young. “But it’s the gas-linked pricing that really draws them in.”
This is a potential alarm bell for oil multinationals.
“Can U.S. exports change the pricing game?” asks Johan Schrijver, managing director for Dutch state business of the credit insurer Atradius which deals with LNG financing.
“Will it reduce, or perhaps put an end to, oil-linked take-or-pay contracts? This is important because the bankability of LNG projects depends very much on the existence of long-term take-or-pay projects with an oil-linked pricing mechanism.”
WoodMac’s Mohanty also said that after 2020, non-U.S. rival LNG exporters might benefit if U.S. lawmakers grow jittery about domestic gas prices. Buyers looking to ensure diversity of supply will also ensure new export regions find customers.
And even if U.S. LNG is shipped via Panama, gas from Western Australia will still have less than half the distance to travel to Japan. In addition, most of the greenfield projects own their own gas, while U.S. exporters have to buy on the open market.
BG, a greenfield developer like Shell and Chevron as well as a U.S gas shipper, is confident the oil price link will stay for as long as supply looks tight.
“We believe oil indexation will remain a key part of the pricing mix in the LNG market for the foreseeable future and without it, some projects outside of the U.S. may not get developed,” said Matt Schatzman, BG group executive vice president for global energy marketing and shipping.
A U.S. LNG report from analysts at Bernstein this week was titled “Forget Saudi America, What about Qatari America?” – a reference to the current leading LNG exporting country.
LNG projects have long been vulnerable to fluctuating politics, price, availability of engineering skills and competition from other energy types.
The Sabine Pass liquefaction export plant is a testament to that volatile history, emerging on the site of a disused regasification import terminal as the cycle turns again.
(c) 2013 Thomson Reuters
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