Currently, there are more than 60 existing import or regasification terminals in 18 countries, including this one in Louisiana, and 26 liquefaction plants in 15 countries.

T?he possible effects of increased imported liquefied natural gas (LNG) shipments on near-term U.S. gas prices is inarguably among today’s foremost worries for gas-oriented producers and their capital providers.

Although the falling U.S. rig count, down to 935 at press time, had bolstered hopes of gas-price recovery, it hasn’t happened yet. Recently, Henry Hub prices hovered around $3.29 per MMBtu, the AECO Canada Hub gas recently traded for $2.76, Waha Hub prices fell to $2.72 and Opal Wyoming Hub gas sold for $2.37.

Aside from low gas prices, another threat literally looms on the horizon. Spot-market shipments of LNG may turn toward U.S. shores this summer, seeking storage as global demand continues to fall, thus increasing already brimming inventories.

While no definitive summer-gas-supply forecast has yet emerged, a plethora of theories abound among consultants, capital providers, regasification terminal operators and even suppliers themselves.

Murray Douglas, North American LNG analyst for Wood Mackenzie, predicts North American LNG imports will rise despite burgeoning shale-gas supply and the economic recession.

“The U.S. can easily accept large volumes of unallocated LNG due to its size, liquidity and significant regas and storage capacity. Some relatively low-cost new liquefaction capacity will compete with domestic shale-gas resources in the U.S. market. This will suppress price and in turn delay some higher-cost domestic developments,” he says.

He predicts further upside to the North American forecast if there is a sustained period of low oil prices. Under this scenario, the oil-linked gas prices in European markets will soften, Asian buyers will switch from gas to oil and spot shipments of LNG will head toward liquid Atlantic Basin markets—the largest and most liquid of which is the U.S.

Ben Dell, senior analyst for Bernstein Research, says gas bears argue that the U.S. has contracted to receive 6 billion cubic feet (Bcf) per day of LNG in 2009 (versus 1 Bcf per day in 2008) and spot LNG will head to the U.S. for storage during the global recession. But he disagrees.

“We believe this is unlikely and LNG imports will be 1.5 Bcf per day, not nearly enough to cause oversupply. We continue to believe the U.S. gas market will grow tighter in the second half of 2009, and that LNG imports will not be a significant issue,” he says.

According to Dell, a tsunami of U.S. LNG imports is doubtful because of three factors. First, delays to start-ups and outages at existing LNG plants have limited net supply growth.

In October 2008, Algeria’s Sonatrach declared force majeure on some of its shipments of LNG due to a cracked pipeline that is cutting output of the chilled gas by 20% for the rest of this year.

In November 2008, Nigeria LNG Ltd., which supplies 10% of the world’s LNG, reported that the Soku gas plant in southern Nigeria, which contributes 40% of its feedstock, was shut down to repair damage caused by thieves that tapped into pipelines. The company warned it may not be able to meet all of its 2009 export obligations.

In January of this year, Qatargas declared force majeure on LNG shipments from its Qatargas I venture, which includes three liquefaction trains, due to mechanical failure.

But force majeure slices both ways. Petronet LNG Ltd., India’s leading LNG importer, recently issued a force majeure notice to refuse two spot cargoes, one due for arrival in late April and one in early May, because of a technical problem at Petronet’s new 6-million-tons-per-year facility.

Second, Dell says, Europe and South America are experiencing strong demand. European storage is 34% below last year and onshore production growth is stalling, while power demand has remained robust. Also, gas supplies from eastern Europe may be disrupted by Ukrainian financial woes. Moreover, imports to South America, where LNG competes with $7-per-Mcf Bolivian gas, could provide “a crucial counter-seasonal source of incremental demand, helping to balance the market,” says Dell.

Third, the history of LNG contracts shows that while Asian import levels have generally matched contracts, U.S. levels have “had virtually no predictive value in terms of eventual LNG deliveries,” says Dell.

Estimates vary
Barclays Capital analyst James Crandell sees both sides of the story. “Some believe higher prices in Europe will attract all excess spot LNG and expect to see little growth for U.S. imports. Others argue that lack of storage capacity elsewhere will push most of the global oversupply into the U.S. despite low prices.”

The range of estimates for U.S. LNG imports in 2009 is unusually wide, he says. Imports will depend not only on global oversupply but also on Atlantic Basin price differentials. Barclays looks to the forward curves on Nymex and the U.K.’s National Balancing Point (NBP) as indicators of where the LNG will land. Spot deals in Europe are generally priced at NBP plus a differential.

Also, fluctuations in exchanges rates can have a significant effect on trans-Atlantic differentials. Although NBP prices are above Nymex in the forward curve, some LNG originating in Trinidad commands better netbacks by offloading in the U.S., even when Europe pays a slightly higher price.

Taking a stand, Crandell predicts that U.S. LNG imports will pick up in the second quarter by about 1 Bcf per day, to average 2.1 Bcf per day, while the third quarter might average 2.6 Bcf per day. He says the fourth quarter will be the most oversupplied, also averaging 2.6 Bcf per day.

Rehan Rashid, analyst for FBR Capital Markets, notes the unfavorable consequences of any increase in LNG imports for U.S. independent gas producers. “The equity implication is a nail in the coffin for marginal production, as basis blowouts near import facilities at the Houston Ship Channel and Perryville (Louisiana) provide another bear-market signal of excess supply.

“The pressure will be on South Texas and Rockies E&P producers to cut capex further, although we are closely watching demand for signs that the system will trade ahead of a perceived 2010 recovery.

At present, global liquefaction utilization is running about 81%, but is expected to increase to 83%, even as new capacities come online and Algeria and Nigeria capacities are fully restored. “This implies an increase from 22.3 Bcf per day traded to 32 Bcf per day by the end of 2010, adding 10 Bcf per day to base-load global gas supply, with most projects priced to withstand gas prices below the current $4-per-Mcf level on a delivered basis,” he says.

In fact, gas prices may fall to $3 per Mcf this summer, according to Zach Allen, president of Pan EurAsian Enterprises Inc. Yet, LNG producers are unlikely to reduce production due to price pressure, he says, because throttling back on production is technically challenging. Also, after stripping out and selling natural gas liquids, producers have an effective cost on the gas “that can be measured in pennies,” so transportation, averaging $2 per Mcf or less, ensures that LNG can be shipped at prices below Henry Hub and still be profitable.

According to Allen, although U.S. baseline supply is about 1 Bcf per day, a 60-day surge of 1.5 Bcf to 2 Bcf per day is likely this summer, unless an unforeseen event—such as South Korea and Japan taking advantage of low prices to fill up before the winter season—comes into play.

U.S. regas capacity
If and when summer LNG storage shipments occur, U.S. regasification terminal operators are ready to receive them. Elba Island LNG, one of six terminals in the U.S., is owned by Southern LNG, a subsidiary of El Paso Corp. Built near Savannah in Chatham County, Georgia, the company recently doubled its facility size and plans to add another 8.4 Bcf of storage for a total of 15.7 Bcf with an ultimate send-out capacity of 2.1 Bcf per day. Royal Dutch Shell and BG have fully contracted existing capacities.

“From the industry, I have heard there is a potential for more LNG shipments to be received by North America because we have storage here,” says Bill Baerge, Elba Island’s manager of investor and media relations. “But the markets ultimately determine where the gas goes.”

Cheniere Sabine Pass Pipeline Co., owner of 2008-commissioned Sabine Pass LNG in Cameron Parish, Louisiana, is also working on an expansion, says Diane Haggard, manager of media relations. The project will add 1.4 Bcf per day to the current send-out capacity of 2.6 Bcf and will include two more tanks.

“We’ve had our four commissioning cargoes, the last in March,” she says. “Total SA started their receiving shipments in April and Chevron Corp. will start theirs in July.”

Cheniere itself is pursuing strategies for LNG purchase, from short-term on the spot market to long-term contracts, says Charif Souki, chairman and chief executive. “We have almost 11 Bcf of storage. When the second phase of the expansion is finished in August, we will be up to about 17 Bcf of storage. We have 2.6 Bcf per day of operation regasification capacity now and by September of this year that will be up to 4 Bcf a day.”

Cheniere is expecting more LNG shipments this year than last year because “we didn’t get many shipments last year,” he says. “But it’s difficult to predict our LNG imports for a number of reasons.”

The facility’s regasification will come online in various phases. “This terminal is very new, so we have to determine what operational utilization is possible. We also have to determine how the three major customers, Total, Chevron and Cheniere Marketing, interact with each other.”

Souki estimates that global demand for LNG is down 10% this year compared to last year, representing about 2 Bcf per day. Meanwhile, supply is increasing as Algerian and Nigerian problems are close to resolution, which will add another 2 Bcf a day into the market.

“There is about 4 Bcf a day that could show up in the Atlantic Basin fairly soon. The same amount will be coming online next year. Altogether, there is a lot of LNG that is going to be available during the next 18 months, some of it starting in the next three months,” he says.

U.S. storage capacity, about 4 trillion cubic feet, dwarfs the U.K.’s 150 Bcf, so the U.S. can easily act as a storage center for excess LNG supply. At press time, U.S. storage was above the five-year average.
“LNG producers will continue to deliver gas all the way down to $2 per Mcf,” says Souki. “I have no doubt of that. They will delay as much as they can, but once they start dumping the tanks of LNG facilities, they have to move the gas. There is not much storage in the producing areas.”

Float-around
Nonetheless, Souki does not see a sustained period of gas prices under $3 per Mcf. “Traditionally, when prices become low enough, there is a market response. Gas could displace coal or some new industries might become more attractive. At the end of summer and into September, October and November, we could have a tight period, but that should become alleviated by winter,” he says.

He predicts global liquefaction capacity will reach mid-30s Bcf per day in 2010. “When you get to that level, it is a very large quantity that is liquid enough to go to the markets with the best prices. The entire natural gas consumption in Asia is 26 Bcf a day. OECD Europe presents somewhere around 45 Bcf a day. So out of the 35 Bcf of global LNG production, about half is going to contract customers and the other half can float around. That float-around is a very large number. So it is going to disrupt a lot of the traditional systems. We are facing a commodity that is going global.”

On prices, he says, “Today, the LNG spot price between northern Europe and the U.S. and Asia are very close, within 50 to 70 cents of each other. It’s the first time I have seen it this way, but it could be the beginning of a trend. When there is this much liquidity in the market, prices should be normalized.”

Bobby Gaspard, vice president, LNG marketing, for Freeport LNG Development LP in Quintana Island, Texas, notes that full capital-cost recovery for LNG shipment averages above $2 per Mcf.

“So at Henry Hub at $2.50, the LNG producers probably won’t deliver LNG into the U.S. Still, I have bought LNG shipped from Northwest Australia at a $2.30 Henry Hub price years ago. The economics come down to what type of carrier ship, how efficient the ship is, how far the LNG is shipped and the efficiency of the source’s liquefaction plant.”

Meanwhile, new capacity additions are under way in the U.S. ExxonMobil’s Golden Pass LNG terminal is under construction near the Texas-Louisiana border. It is expected to come online in mid-2010, delayed from its planned 2009 start-up due to damage from Hurricane Ike, according to spokesperson Kimberly Brasington.

“Hurricane Ike repairs are under way on buildings, equipment, piping, and LNG tanks that were impacted by storm surge water,” she says. “The plant is designed with the capacity to process 15.4 million tons per year of LNG, which is equivalent to approximately 2 Bcf per day.”

When completed, the facility will include unloading facilities, five 155,000-cubic-meter storage tanks, regasification equipment and a 78-mile pipeline to connect to several natural gas lines that feed Texas and much of the eastern U.S.
Sempra Energy reports its new LNG regasification terminal on the Calcasieu Channel, in Hackberry, Louisiana, will begin commercial operations in mid-2009. The terminal has 1.5 Bcf per day of initial send-out capacity, with room for expansion, and three 160,000-cubic-meter storage tanks.

Elsewhere, Dominion Cove Point LNG’s facility in Calvert County, Maryland, recently commissioned its storage-expansion project to achieve 14.6 Bcf.

The amount of LNG that will be shipped to and stored in the U.S. during the summer months is still unknown. Spot shipments will be bought and sold during transport, some with only a few weeks’ prior notice to import terminals before making landfall. What is certain, however, is that any amount of surplus gas sent into the U.S. markets or storage will help ensure low gas prices throughout this summer.