By John Kemp
LONDON, Sept 13 (Reuters) - Large-scale gas exports from theUnited States will narrow the gap between U.S. domestic pricesand those in Asia, but the boost to U.S. domestic gas prices islikely to be smaller than U.S. gas producers hope and consumersfear.
In October, gas importers in Japan and Korea will pay morethan $15 per million British thermal units for shipments ofliquefied natural gas (LNG), compared with under $10 forimporters in Britain and less than $4 for importers in theUnited States, according to the U.S. Federal Energy RegulatoryCommission.
No wonder gas producers and traders want to exploit thearbitrage, buying gas in the United States at prices linked toHenry Hub (currently under $4), liquefying it, and exporting itto customers in Japan, Korea, China and India at formula priceslinked to the Japan Crude Cocktail (which currently values gasat more than $15).
For their part, Asian buyers want to break the oil link andpurchase LNG at lower prices closer to Henry Hub. And domesticgas consumers in the United States fear that once exportingstarts in earnest they could see the price they pay for naturalgas double or more as American and Asian converge.
The problem with all these hopes and fears is that they failto account properly for the enormous costs of running an LNGoperation.
LNG prices in Asia are very unlikely to fall anywhere nearto the level prevailing in the United States because exportershave to recover the enormous capital and operating costs ofliquefying and transporting the gas.
Conversely, domestic U.S. gas prices will not rise anywhereclose to those in Asia because the arbitrage window would closelong before they approached that level.
EXPENSIVE BUSINESS
In a series of careful economic studies, Emil Attanasi andPhilip Freeman of the U.S. Geological Survey estimatedliquefaction and transportation costs from a hypothetical planton the southern coast of Alaska to Yokohama in Japan.
Costs would range from $6 to $10 per million British thermalunits, depending on how much the gas could be bought fororiginally and the project's assumed rate of return, accordingto Attanasi and Freeman ("Commercial possibilities for strandedconventional gas from Alaska's North Slope" June 2013).
If gas could be purchased in Alaska for $4 per million BTU,treated and piped across the state for another $3-4, it wouldstill need to be sold in Yokohama for between $14 and $19,depending on whether the project tried to achieve a rate ofreturn of 9 percent or 15 percent.
In practice, LNG exported from facilities along the U.S.Gulf Coast and Atlantic seaboard would be cheaper. UnlikeAlaska, projects would be able to use the existing gastransmission network. No new pipelines would need to be built totransport gas to the liquefaction facilities.
Many of the most advanced export LNG projects are beingconstructed at locations along the U.S. Gulf and Atlantic Coaststhat were originally built to import LNG. Much of theinfrastructure, including storage tanks and deepwater berths,can be re-used, slashing the overall capital costs.
By avoiding the cost of new pipelines and re-using storagetanks and berths, U.S. LNG exporters may be able to cutdelivered costs to Japan by $3-4 per million BTU.
Even so, it is hard to see how LNG could be delivered fromthe United States to Japan for less than $10 per million BTU.
Conversely, it is hard to see how LNG exporters could affordto buy gas in the United States for more than $6 and still hopeto make money.
FOREIGN COMPETITION
The United States is not the only country hoping to supplymore gas to fast-growing markets in East and South Asia.
China could acquire substantial quantities of pipeline gasfrom Russia and Central Asia for a delivered price in Shanghaiof $7-11 per million BTU, according to an evaluation ofalternative supplies by Attanasi and Freeman ("Meeting Asia'sfuture gas import demand with stranded natural gas from CentralAsia, Russia, Southeast Asia and Australia" March 2015).
China, Japan, South Korea and India will also be able toobtain large volumes of LNG from Australia, Malaysia andIndonesia for landed prices ranging from $9-14 per million BTU.
With so many potential rival suppliers in the Asia market,U.S. LNG will need to be delivered to Asian ports at prices nomore than $14, and perhaps less than $12.
In those circumstances, the netback price at the point ofexport in the United States is unlikely to exceed $6 or $7 permillion BTU.
In its study for the U.S. Department of Energy, NERAEconomic Consulting reached a similar conclusion. NERA predictedexports would push future domestic gas prices up to around $4and $8 in real terms, with most scenarios putting gas pricearound $6 ("Macroeconomic Impacts of LNG Exports from the UnitedStates" Dec 2012).
ALASKA'S NORTH SLOPE
Interest in LNG exports continues to pick up. On Thursday,Alaska's Natural Resources Commissioner Dan Sullivan announcedthe state had signed a memorandum of understanding with Japan'sBank for International Cooperation (JBIC) to explore a number ofnatural resource projects, including LNG exports.
Alaska's North Slope oilfields contain roughly 35 trillioncubic feet of stranded gas. TransCanada, ConocoPhillips, BP and Exxon Mobil are jointly studyinga possible LNG project to monetise it by building a pipelineacross the state and a liquefaction facility on the south coastthat would send cargoes Asia.
Evaluating the project, however, Attanasi and Freemanwarned: "Alaska's gas exports to Asia will likely encountersubstantial competitive pressures."
Even if stranded North Slope gas could be delivered to atreatment plant at Prudhoe Bay on the north coast at a minimalcost of $2, the delivered cost in Yokohama would still need tobe around $13.50 for the project to earn a 12 percent rate ofreturn.
Other suppliers could deliver 149 trillion cubic feet, threetimes as much, to Yokohama at prices cheaper than Alaska's NorthSlope.
COST, RISK AND PRICING
Construction costs for LNG export facilities are so high noproject will go ahead unless substantially all the potentialoutput has already been pre-sold.
Would-be U.S. LNG exporters have already signed firmcontracts covering more than 34 million tonnes per annum (mtpa)or around 4.7 billion cubic feet per day (bcf/d).
Three of the four export projects that have been approved sofar by the U.S. Department of Energy have already sold theirentire planned capacity, much of it to customers from Japan,Korea and India.
LNG exports will only remain profitable if U.S. domestic gasprices remain low and European and especially Asian gas pricesstay high, or if the prices of LNG cargoes in Europe and Asiacan be successfully tied back to the cost of acquiring the gasin North America.
The question is how to share the risk. So far, all theprojects have succeeded in passing price risk to the buyer.
In 2013, Sabine Pass has sold future LNG to Total and Centrica using a two-part tariff: the first fixedpart compensates Sabine Pass for the capital and operating costsof the facilities that will be built, the second variable partreimburses Sabine Pass for the cost of fuel and feed gaspurchased.
Using a different form of contract, Freeport LNG hasexecuted tolling agreements with BP, Osaka Gas, and ChubuElectric, which force them to pay for the use of theliquefaction facilities on a take-or-pay basis, but leave themresponsible for sourcing the gas.
BP (BP.)
Centrica (CNA)
