High natural gas prices in the United States have energized spot trading in LNG shipments, with over half the cargoes received in the U.S. recently coming from spot sales, BP’s regional manager for the Americas and the Atlantic Basin said last week.
The Atlantic Basin spot market in LNG cargoes “has grown dramatically, with the U.S. now overtaking Europe as the largest importer of spot cargoes,” Philip Bainbridge told a Washington DC conference hosted by LNG Express. Bainbridge said the high U.S. gas prices have provided sufficient netbacks to draw cargoes from as far away as Australia, Abu Dhabi, and Nigeria. BP is aiming to grow its LNG spot market trade and “currently has four vessels on the water trading spot cargoes on our behalf.”
How large an LNG market the U.S. can sustain was the prime subject of the conference, which included representatives of the four existing LNG receiving terminals in the Lower 48 and proposed new terminals, as well as representatives of exporting countries. The two plants currently operating at Lake Charles, LA and Everett, MA, have a combined send-out capacity of about 1.2 Bcf/d. A third terminal, El Paso’s Elba Island, GA facility, on its Southern Natural Gas System is expected to start up in October with a send-out capacity of about 440 MMcf/d. The future recommissioning of Williams’ Cove Point, MD facility to accept imports, plus expansions of all the existing terminals, is expected to bring the total send-out capacity for the existing facilities to 2.73 Bcf/d, according to El Paso’s estimate.
A number of new terminals have been proposed, with estimates of total North American LNG imports by 2010 running between 3.5 to 6.5 Bcf/d.
Development of natural gas fields and liquefaction facilities close to home in Trinidad and Tobago in the Caribbean sparked the rejuvenation of the Elba Island facility, according to Pat Pope, vice president of El Paso Energy Services. The facility is expecting to handle about 65 cargoes a year, with a send-out of 160 Bcf/year, which could be expanded to 246 Bcf/year.
“Eventually, over the passage of time, I do see the emergence of a commodity LNG trade,” Pope agreed. But, terminals will not become commoditized, he added. Terminals serve as substitutes for transmission and will operate with a portfolio of supplies. “We’re in the infrastructure business. We view LNG as a catalyst for growth. It’s like having a producing field off the coast of Georgia.” El Paso is looking at the terminal as a central point, which can spawn new generation and cogeneration facilities in the area.
The Distrigas facility in Everett, MA, formerly owned by Cabot Corp., which was bought recently by Tractabel LNG North America, a subsidiary of the European-based Suez conglomerate, also has developed a new market. It is expanding to supply a new 1,550 MW power generating plant to be built alongside its terminal by Sithe Industries.
While Elba Island and Distrigas have a market area advantage, CMS Panhandle Vice President Keith Meyer said his company’s Louisiana facility benefits from the pipeline infrastructure in place to carry supplies from the Gulf Coast to the rest of the United States. There is the opportunity to replace declining Gulf Coast production with imports. Lake Charles took in 55 cargoes last year and expects to handle between 55 and 65 shiploads this year. It is looking to expand and boost its send-out from 700 MMcf/d to 1 Bcf/d. The terminal has the advantage of being able to handle a wide range of ships and quality of gas.
The economics of natural gas prices will drive expansions of existing plants and greenfield projects, the participants agreed. Meyer said he thought new project developers were looking at an average $3.50/MMBtu gas price to make their projects viable.
Jim Jensen, formerly of Jensen Associates, warned against banking on high short-term gas prices in conceiving long term projects. Jensen agreed the industry is seeing more than a short-term market correction, noting that forecast models “have overestimated the elasticity of North American gas supply in the face of accelerating gas demand, and thus underestimated future prices.” Jensen, noting that some large customers last winter switched not just to resid, but to distillate oil as well, argues for a new fuel-switching benchmark of 90% of the refiners acquisition cost of oil, instead of the old benchmark of 58% of RAC (with $25 per barrel oil, that would put the benchmark at $3.90 MMBtu).
But in projecting a 30 Tcf or higher market, “they have probably also overestimated future demand. Thus project developers cannot escape the risk that an ebullient industry will once again overdo the supply side of the balance and create a new bear market–if only for a time….there is still no substitute for an intelligent assessment of risks before proceeding with a new LNG project,” the veteran energy analyst advised.
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