Anyone watching North American natural gas prices might blanch at the thought of christening a liquefied natural gas (LNG) import terminal, but Spain’s Repsol forged ahead recently with the opening of its Canaport facility at Mispec Point, near Saint John, NB. Repsol Energy North America (RENA) President Phil Ribbeck noted that winter is coming and he expects cargo traffic to ramp up soon and into next year.

Gas sendout from the Canaport terminal began July 11 and has been running about 200 MMcf/d, Ribbeck told NGI. “We contemplate that the facility is going to be much more utilized in the coming months as well as over the period of next year,” he said. “That’s based on — number one — our arrangements in the marketplace and — number two — the likelihood of more LNG supplies coming available on the global market next year. Over the course of next year I’d like to build up to 600-700 MMcf/d [of gas sendout].”

(The most recent data from Tudor, Pickering, Holt & Co. Securities Inc. shows U.S. regasification terminal sendout has been averaging 1.33 Bcf/d of late, which is up from 0.9 Bcf/d a year ago.)

Repsol partnered with Canada’s Irving Oil on Canaport, the first terminal of its kind to be built on the East Coast of North America in 30 years and the first ever to be built in Canada. It’s official opening last month marked Repsol’s entry into the North American gas market (see NGI, Sept. 28; June 22), the largest in the world, Ribbeck enthused.

“So far the LNG has been supplied [to Canaport] from Trinidad and Tobago and Egypt, and we expect we’ll continue to get supply from Trinidad and Tobago, and we’ll purchase third-party supplies from various places as we go forward, some on spot and some on term,” Ribbeck said. “I’d personally like to have something in the range of maybe 500 MMcf/d on a term contract basis and then about 100-200 on spot, on average. That’s what I’m going to shoot for.”

Repsol isn’t the only foreign oil company to lately enter North America on the back of LNG trade. Russia’s OAO Gazprom recently opened a marketing and trading office in Houston and has said its business will include importing LNG as well as orchestrating trans-Atlantic swap transactions (see NGI, Oct. 5; June 15). Gazprom Marketing & Trading USA President John Hattenberger said the firm has been doing swaps between North America and Western Europe. “We intend to be a physical supplier [of gas] all across North America through swaps and LNG,” he said recently (see related story).

According to Ribbeck, swapping LNG cargoes is a tricky matter.

“We’ve done swaps. We’ve done various types of arrangements,” he said. “We always look for ways to bring efficiency into the overall logistics and supply chain. But swaps, though, aren’t that easy. I’ll be quite honest with you. A pure swap is ‘OK, I’ve got 10,000 units here and you want them so you give me 10,000 units over here where I want them and we’re even. Or you pay me 10 cents because mine is more valuable than yours or whatever the case may be in that location.’

“Whereas with LNG supply, there’s never two ships that have the exact same amount of Btus on board. You have to handle a lot of different things to handle those swaps. But we have done swaps.”

Ribbeck said swapping an LNG cargo with indigenous gas supply is not very common currently, but he allowed that “it is something that could be done.”

Trading practices in the LNG market have continued to evolve since the late 1990s, Ribbeck said. Back then, Amoco Corp. and Repsol — major shareholders in Trinidad and Tobago’s Atlantic LNG — struck a deal for Repsol to buy LNG from the liquefaction facility, giving Amoco a guaranteed market for its liquefied gas.

“…[T]hat kind of changed the way things were being contracted for, and since that time you’ve had all kinds of different things happen with respect to the way that LNG was sold by projects,” Ribbeck said. He noted that Peru LNG (see NGI, Jan. 29, 2007) has a commitment from Repsol, which is a partner in the project, “to take 100% of the gas and market it at a price that was determined to be acceptable for the project to proceed.”

The spot market for LNG cargoes has become more fungible, thanks in part to more flexible contracting. Ribbeck noted that European LNG buyers were recently able to take advantage of weak spot LNG prices by reducing their oil-indexed contract takes and buying cheaper spot cargoes. “You’ve seen a lot of different things happen that have really impacted the way LNG has been traded,” he said.

“You’ve seen a deterioration in the LNG spot price. If you recall…in December…you had prices that were pretty high. They were still ranging $18-19/MMBtu over in the Far East when they’re were peaking. They’ve dropped off considerably since then. My understanding from the conference that I was at [recently] is that the Far East markets don’t have an appetite to contract for additional quantities at the moment. And in fact, they’ve turned back as much as they could turn back of their base contract quantities and now they’re not going to be able to purchase spot quantities unless they have a fairly significant winter. So in any case we’ve seen a major shift in the overall dynamics of the LNG spot marketplace.”

Ribbeck does not expect to see price convergence of the Atlantic and Pacific basins. In Asia LNG prices are indexed to the Japan Customs Clearing price. In Europe LNG contracts are indexed to a spot gas and fuel oil combination, and in the United States, Henry Hub is the benchmark.

“The two [basins] are not connected at this point in time,” Ribbeck said. “Will it ever get there in a strong way? I think if you look at it strictly from a trader’s perspective, traders don’t want to see necessarily one set price because it doesn’t do anything for them; it doesn’t give them anything to do and try to bring efficiencies into the system.”

Gazprom’s Hattenberger has said he does not expect the LNG industry to ever rally around a single price for the commodity (see NGI, May 25).

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