By Patrick Reames
Managing Director, The Americas
CommodityPoint, A Division of UtiliPoint International, Inc.

Italy’s Statoil and Russia’s Gazprom announced this week that they have entered into a preliminary agreement that will see additional volumes of LNG (liquefied natural gas) hitting the U.S. markets in the coming years. Under the agreement, Gazprom will receive up to 200MMBtu/day of LNG regasification capacity from Statoil at the Cove Point terminal on the shores of Chesapeake Bay for up to 20 years; Statoil will buy an additional 200MMBtu/day of LNG from Gazprom which will also go to Cove Point; and Statoil will sell non-LNG supplies of natural gas to Gazprom at various trading points around the United States for five years. While it does appear to add up to a win-win for both companies--Statoil gets out of under-utilized capacity at Cove Point and Gazprom finds an additional market for their large supply of LNG and increases their marketing presence in the United States--this deal probably should not be viewed as a indicator of a bright future for LNG in the United States.

The reality is that LNG continues to be a fuel source of great potential but little performance in the United States. Of the LNG that has landed in the United States in the last couple of years, 80 - 90 percent has been volumes that have arrived under long-term agreements and have come in at only two ports, Everett in Massachusetts and Elba Island in Georgia. Those long-term agreements are not necessary tied to current market realities, as Everett volumes are brought in under a 40 year agreement that started in 1971 and Elba is covered by a 17 year contract that started in 2002. And while additional volumes have come into Cove Point, and the odd tanker has landed at various Gulf ports over the last year, LNG continues to be a minor player in the U.S. energy markets, comprising less than 2 percent of the total U.S. gas supply.

Despite various rosy forecasts over the last several years touting the potential of LNG in the United States, and despite multiple billions of dollars having been spent to make those forecasts a reality, LNG has yet to find a firm foothold in the U.S. marketplace. In fact, U.S. regasification capacity now stands at around 9.4 Bcfd (representing about 40 percent of the global regas capacity), but only about a 1 Bcfd left those facilities in 2008, and sendout from U.S. LNG facilities has never exceeded 3.2 Bcfd, a volume reached in 2007.

Two factors continue to conspire against LNG in the United States: 1) the competition for LNG from industrialized countries that have little or no domestic natural gas supplies (such as Germany and Japan), and 2) new drilling technologies and completion techniques that have made US non-conventional sources of natural gas more economical.

According to FERC, current global prices for LNG range from more than $6/MMbtu in Japan, to the high $3.00’s along the Gulf Coast of the United States, with European markets trading in the mid to high $4 range. In fact, according to the latest FERC report, dated Nov. 6, 2009, every potential landing point in the United States is priced below the rest of the world. Still, the price differentials are not overwhelming and, depending on the shape of any potential global economic recovery (or potential market upset), U.S. prices could become more competitive in the near future, assuming industrial and weather related demand remains low in Europe and Asia. Unfortunately, given little native gas production in the industrialized countries in these regions, any up-tick in demand in these markets will most likely see the United States on the bottom end of prices in the LNG markets once again.

Over the last several years, another impediment to LNG market growth in the United States has been the growth in production from unconventional sources of natural gas--tight sands, coal seam methane and shale--which now make up more than 60 percent of production in the United States (excluding Alaskan gas production, a portion of which, ironically, is liquefied and shipped to Japan). Despite the relative high cost of developing these sources compared to conventional gas reservoirs, (with development costs from unconventional sources estimated at $3/MMbtu on the low end, to $6/MMbtu on the high end), high gas prices in 2007 and 2008 encouraged significant development, resulting in increased production from these long-lived sources. Even now, with the U.S. drilling rig count down more than 50 percent from its high in September 2008, there remains great potential to mobilize additional rigs should gas prices continue the recovery that we’ve seen in the last couple of months. With gas trading consistently above $4/MMBtu, we have seen rig counts starting to come up; and with those new rigs, new production coming on board. This is of course a self-limiting exercise, as new incremental production, without new demand, will keep gas prices “capped.”

The question is, which source will set the price ceiling, domestic gas from unconventional sources or LNG imports? Over the last couple of years, development costs for unconventional natural gas have, on average, been lower than the global market price for LNG; and despite the global economic crisis which has depressed demand for LNG overseas, unconventional gas continues, at least for now, to be the cheaper alternative.

While Gazprom and Statoil have apparently found a deal that works for them and will result in some additional volumes of LNG coming to the U.S. market, it probably shouldn’t be seen as a harbinger of greater things to come for LNG. Unfortunately for LNG investors, the United States, with potentially up to 2,000 TCF of unconventional natural gas reserves (an almost 100 year supply at current demand), is well positioned to offset current production declines and meet any incremental demand from its own domestic sources for many years to come.

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