The East Coast of North America is faced with a significant oversupply of liquefied natural gas (LNG) import capacity that will persist well into the next decade, according to a consultant’s analysis.
PFC Energy forecasts that as new LNG regasification terminals are constructed, capacity will exceed the supply available from producers in the Atlantic Basin and Middle East with a gap between regasification capacity and available LNG as great as 90 million tons per annum (MMtpa), or4.35 Tcf, by 2012. This gap will shrink over the longer term, but by 2017 is still expected to be around 50 MMtpa, or 2.4 Tcf.
PFC Energy’s findings have a lot in common with those of the Energy Information Administration, which reported earlier this month that given global LNG supply constraints, overall capacity utilization at the U.S. LNG import facilities is expected to remain below 50% through 2030 (see NGI, March 10).
Terrell Benke, a manager in the upstream and gas group at PFC Energy, said, “While 19.5 Bcf/d in eastern North America regasification capacity will be on-line by 2012, utilization rates will lag significantly, but unevenly, with the lowest utilization rates for terminals without contracted supply in areas where prices are lower — mainly the Gulf of Mexico.”
Benke marked the cause of the overbuild to robust demand growth and relatively high prices along with the belief that market access would be the limiting factor in the commercialization of the many proposed liquefaction projects. While regasification terminals proved easier to develop than expected, escalating costs have slowed the build-up of liquefaction projects. PFC Energy expects the total liquefaction capacity in the Atlantic Basin and Middle East to be about 178 MMtpa (8.6 Tcf) by 2011, and while this represents a more than doubling since 2005, it is less bullish than the 300 MMtpa (14.5 Tcf) level that regasification terminal developers were expecting to be available by early in the next decade, PFC said.
The Washington, DC-based firm said it expects much of the contracted new supply to flow to Europe and Asia, with a much smaller portion dedicated to North America. Some of the remaining LNG will end up in North America, either through companies with destination flexibility and an active trading mentality (such as Shell or BG) seeking high prices at North American terminals, or through currently uncontracted LNG coming in under future contracts or on the spot market. But this will be limited by the attractiveness of North American gas prices relative to prices in other markets.
The highly competitive nature of the downstream market in North America often prevents gas prices from rising to the same levels as can be supported in Asia or parts of Europe. Also, except for LNG from Trinidad, Atlantic Basin and Middle East supplies face an additional 30-80 cents/MMBtu transportation cost for deliveries to the U.S. market.
Even if all currently uncontracted and flexible LNG in the Atlantic Basin and Middle East were to be added to North American supply, PFC Energy still estimates that the gap between terminal capacity and available LNG on the East Coast of North America could reach 70 MMtpa (3.4 Tcf) by 2012. And the gap could become larger as these estimates only include existing and under construction terminals — if additional regasification capacity is added, the gap will be greater.
In addition, PFC research has found that while the gas industry has increasingly looked to the spread between Henry Hub (HH) and the United Kingdom’s National Balancing Point (NBP) — the most liquid gas trading point in Europe — prices to forecast relative LNG flows into Europe and the United States, the spread is not a good indicator for determining gas flows into the United States. This is despite its seeming success during last summer’s LNG cargo boom into the United States. The indicator is an easy one to point to given that the prices are readily available and the last three summers have shown an increasing relationship between the spread and LNG flows. But linking the two when forecasting LNG flows is a mistake, said Nikos Tsafos, a PFC analyst.
“U.S. LNG flows were not determined by demand patterns in the UK last summer but instead by a production increase out of Trinidad, which raised total supply for the Atlantic Basin, as well as lower demand early in the year in countries such as Spain and Korea.”
An analysis confirms that the link between the HH-NBP spread and LNG flows in 2007 was incidental, even if statistically strong, the consultant said. August 2007 was the last month of high U.S. LNG imports, while LNG demand in the UK did not pick up until November, and even then it remained under 2006 levels. The UK Interconnector (IUK) with Belgium remained in export mode for most the year, and it was only in November 2007 that the UK imported more from the IUK than it exported.
So while the U.S. was not importing as much LNG after August 2007, the gas was not flowing to the UK. Unfortunately, there is no fresh market signal that can be readily swapped out with the HH-NBP spread that would provide any additional accuracy. Yet a close look at the Spanish power price and storage levels indicates the appetite for gas in Europe — for example, based on current power prices and the dollar-versus-euro exchange rate — Spanish power producers can pay around $15/MMBtu, a significant amount over HH prices in the U.S.
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