THE TIDE RISES FOR LNG

Wanda Avila is a business writer based in Washington, DC.

Now that the majority of new powerplants in the States are gas-based, and supplies from traditional sources like Canada may be waning, the liquid natural gas (LNG) ship could be coming into port right on schedule.

In Japan, where limited natural resources and an inability to import natural gas via existing pipelines forces the alternative, LNG is a staple fuel. According to the Gas Technology Institute (GTI), Japan has a total of 23 import facilities, almost eight times the number of any other country with import facilities. Most current demand for LNG in the States, on the other hand, is for supplying additional energy during peak-demand periods. According to GTI, there are 62 US peak-shaving liquefaction facilities.

Still, not since the energy crises of the 1970s have LNG imports looked so promising. Higher natural gas prices, the discovery of new natural gas sources overseas, and lower costs for producing and shipping LNG have contributed to a renewed interest in it, according to the Energy Information Agency's (EIA) Annual Energy Outlook 2002. Overall US natural gas demand is expected to grow by almost 50 percent between 2000 and 2020—according to EIA, natural gas consumption will grow from 22.83 trillion cubic feet (TCF) in 2000 to 33.78 TCF in 2020. While the demand for natural gas will increase in all sectors, most of it will come from electricity generation. (See Figure 1.)

Neither domestic production nor Canadian imports are likely to meet the increased demand, industry analysts say. Domestic production will probably be able to supply only about 28 TCF in 2020, according to EIA projections. And gas-hungry electricity generators are expected to triple their demands by 2020, growing faster than any other sector.

Where will all this natural gas come from, then? Gas-rich countries such as Trinidad, Algeria, Nigeria, and Australia may be part of the answer. And at present, the only economically feasible option for importing natural gas from overseas is by liquefaction—liquids are denser than gases—and shipping it via large, specialized LNG tankers.

Filling a Gap
The significant amount of domestic natural gas drilling activity in late 2000 and early 2001 resulted in only a minimum increase of gas deliverability. Ronald Barone, managing director of UBS Warburg's research department, points out, "The fact is, we are going to have to get gas from somewhere, and I think increased imports of LNG are most likely." Barone adds that the increased need for LNG will begin "probably as soon as the United States comes out of the recession it is currently in."

Even if new North American gas reserves are discovered, they likely will be unable to meet demand. Most of the reserves in the three most promising frontier areas in the United States—Alaska, Rocky Mountains, and the offshore Gulf—can't be touched because they are on federal lands. In the Rocky Mountains alone, a recent Department of Energy analysis found that nearly 68 percent of the area's technically recoverable natural gas resource is either closed to development or under significant access restrictions. Granting access could yield as much as 79 TCF of natural gas.

Still, even if these areas were opened, they would have little impact on LNG imports, says Phyllis Martin, an energy analyst at EIA. As gas supplies increase, prices will fall; and as prices fall, consumption will increase. "With the terminals already in place, they will keep on bringing [LNG] in to meet the increased demand," says Martin.

To develop resources in the Gulf, new technologies for deep offshore drilling also will be needed. "Reserves in all three areas would be expensive to develop," says Keith Meyer, CMS Energy's vice president of marketing. "It might be cheaper for us to import LNG than to develop these reserves," he speculates. And even if legislation to open places like the Alaska National Wildlife Refuge was passed, users probably would not see that gas for several years, due to political gridlock and the need for new pipelines to transport the gas.

Canada, which contributes about 94 percent of all US gas imports, will probably be unable to boost its exports enough to keep up with increasing US demand, according to the Canadian Gas Potential Committee. Production in Alberta, which accounts for 85 percent of the country's gas output, is expected to peak in 2003 and then decline by 2 percent annually from 2005 to the end of this decade. Further, Alberta is expected to consume more of its own gas to develop the province's huge oil-sands deposits, leaving less gas available for export. In addition, Canada's "near frontier" areas, once thought to contain gas reserves so vast they could eventually replace western Canada's, now account for only 15 percent of the country's remaining marketable gas. LNG stands ready to pick up the slack.

Price Consideration
But the future of LNG imports depends also on the price of natural gas. "Gas prices will have to be consistent and high enough to make LNG imports profitable to its producers," says Mary Menino, manager of North American natural gas at Energy Security Analysis.

Shipping costs, which vary with distance, add to the cost of LNG. Tankers must offload their cargo within a certain period of time, since a percentage of the extremely cold liquid burns off each day, making long hauls at sea unprofitable. That usually means LNG imports from Trinidad—which is 2,200 miles away from the same US terminal—are more attractive than imports from Algeria 3,800 miles away.

In 2000, 44 percent of US LNG imports came from Trinidad, according to EIA. Qatar and Algeria supplied an additional 41 percent. Nigeria, Oman, Australia, Indonesia, and the United Arab Emirates together supplied the remainder. (See Figure 2.) The costs of liquefaction, shipping, and regasification push the cost of LNG to between $2.75 and $4.00 per million BTUs, according to Cheniere Energy, an oil and gas company in Houston. That means that LNG importers have to be able to sell their LNG for around $3.00 per million BTUs on the East Coast and around $3.50 on the West Coast to make a profit, according to Barone. The average prices in Figure 2 are a combination of landed prices (including production and transportation costs), tailgate prices (including production, transportation, and regasification costs), and LNG bought on the spot market and under long-term contracts.

Sometimes LNG can be cheaper than domestic gas. For example, importing LNG is more attractive economically than piping gas from Texas to New England. Also, LNG often sells low on the spot market. Tankers that are carrying a fuel prone to dissipation the longer they stay at sea sometimes find themselves willing to sell LNG on the spot market for bargain prices.

LNG Doors Are Reopening
Although terminal reopenings signal renewed interest in LNG, the number of existing US terminals demonstrates a challenge facing the LNG import industry—insufficient, and expensive, infrastructure. As of last spring, the United States had only two active LNG terminals, one in Everett, MA, and one in Lake Charles, LA. The Everett terminal, operated by Tractebel's subsidiary Distrigas, includes two LNG storage tanks with a combined capacity of 3.5 billion cubic feet (BCF), and meets between 15 percent and 20 percent of New England's gas demand each year. The company is expanding the terminal with four new vaporizers, capable of delivering another .6 BCF per day (which will fuel a nearby 1,550-megawatt natural gas-fired, combined cycle plant). Another receiving terminal in Elba Island, GA, which had been dormant since the early 1980s, reopened at the end of 2001; and a fourth terminal at Cove Point, MD, was preparing to open this year.

But besides reopening or expanding terminals, there are other indications of growth in the industry. Since LNG has primarily been used as a peaking fuel, terminals have typically operated on a spot-shipment basis. The only long-term contracts in place were with Trinidad and Tobago.

That is changing, however, according to John Barnett, spokesman for CMS Energy, which owns the Lake Charles terminal. As recently as last year, the industry has seen a significant move toward long-term contracts. According to Barnett, CMS received more than 20 expressions of interest in long-term deals during its 2001 open season. CMS is now expanding its facility to meet the terms of a contract that it signed with BG LNG last spring, says CMS's vice president of marketing, Keith Meyer.

Long-term contracts are also making it easier for investors to swallow the initial costs of building needed LNG facilities. These long-term supply purchase agreements—and their accompanying revenue predictability and stability—are making multi-billion dollar investments possible that previously would have been unthinkable to project sponsors, according to Standard & Poor's Peter Rigby.

A Worthwhile Investment
The large, upfront capital investments required to begin importing LNG can make the imported fuel less competitive than domestic natural gas. The highest price tags of an LNG project are the liquefaction facility and tankers—among the most expensive merchant ships ever built because of their double hulls and special linings. Technological improvements have lowered costs for the tankers, however, by 50 percent over the past decade, says Rigby. As a result, in 2001, a record 48 tankers were ordered, according to Lloyd's List.



The receiving terminal, including a jetty and unloading facilities, storage tanks, regasification facilities, and connections to pipelines, are all part of the necessary LNG infrastructure. Recent activities to build new LNG import facilities and purchase new tankers, though, are proving that companies in the business feel that demand for LNG will rise high enough to pay off the expenses of building the infrastructure.

With the stated aim of becoming a "leading worldwide LNG merchant," El Paso Corporation has announced plans to open three terminals, all of which will be operational in 2005, according to Aaron Woods, company spokesman. In the Bahamas, El Paso is establishing a terminal with a send-out capacity of about .5 BCF per day of gas and a pipeline connection to Florida. South of the border, the company is developing (with Shell Gas and Power), a terminal in Altamira, Mexico, with a potential capacity of 1.3 BCF per day. In the United States, El Paso is building a terminal on Radio Island, NC, with a send-out capacity of around .3 BCF per day, and is proposing a pipeline to connect the terminal with industrial markets and power generation facilities in eastern North Carolina.



But El Paso Corporation is just one of the many companies that are in the process of establishing new receiving and gasification LNG terminals.

Before their merger, Chevron and Texaco had each made plans to open new LNG terminals. Chevron had announced that it was evaluating several locations for the construction of a terminal with a capacity of 500,000 CF per day that would serve the US West Coast as early as 2005, and Texaco had announced plans to develop a new LNG terminal in the US Gulf of Mexico, with a potential capacity of up to 2 BCF per day.



Cheniere Energy also has acquired options to buy three sites on the Texas Gulf Coast for the purpose of building LNG receiving terminals. Each of the terminals will have an average annual capacity of 365 BCF of gas per year. According to Charif Souki, Cheniere president and CEO, "We believe that LNG will become a critical component of gas supply within the next decade." Other companies taking the LNG plunge include Sempra Energy, CMS Energy Corporation, and Dynegy, which announced last July that it planned to build a new terminal in Hackberry, LA that could be capable of receiving and processing 1.5 BCF per day.

Internationally, Australia, Portugal, Spain, Italy, and some areas in South America are expanding or building new LNG import, export, and production facilities. China and India, to some extent, are positioning themselves to become key importers of LNG into Asia, according to EIA. In January 2000, the Chinese government approved its first plan to import LNG to its southern region of Guangdong. India, on the other hand, continues to work out its LNG import policies, although expectations there for rapid growth in consumption are high.

But How Safe Is It?
The safety of LNG has been controversial since the first LNG peaking plant was built in 1939 in West Virginia. This controversy intensified (as it generally did for every explosive fuel) after September 11, 2001. Outside Boston, the US Coast Guard banned tankers delivering LNG to the Everett terminal. City officials expressed fears that a terrorist attack on an LNG tanker could result in a catastrophic explosion or fire that would endanger city residents living near the Boston Harbor.

A Federal Energy Regulatory Commission (FERC) decision to pull back approval of the reactivation of Cove Point last November also resulted from terrorism fears. There especially were concerns that the Cove Point facility was within three miles of the Calvert Cliffs nuclear powerplant, and that an attack on an LNG tanker passing near the plant could cause a nuclear meltdown. Not much later, however, FERC approved Williams' plan to reactivate the terminal. The favorable final decision issued in December last year could set a precedent for similar future decisions.

Industry experts say that fears about the safety of LNG are largely unwarranted. "LNG is just another form of energy," says Jeff Beale, president of CH-IV International, an LNG technology consulting firm. "If we're going to get excited about LNG, we've got to get excited about every other dangerous product carried over the seas as well." Beale points out that the Coast Guard ranks LNG as much less hazardous than gases such as ammonia, butane, and propane.

BP's Daren Beaudo agrees that LNG's characteristics "constitute far fewer risks than the myriad of other hydrocarbons, chemicals, and fuels that are transported in far greater concentrations over public roadways and waterways every day."

"LNG is a preferred hydrocarbon because of its physical composition and its safety track record," Beaudo goes on to say. LNG will explode only when ignited in a closed environment, for example. It will not explode in the open air. "We have to demonstrate credibility and reliability to the public every day. And I think we—and other LNG shippers—have done that since 1964 when LNG first began shipping commercially," he says.

Several LNG technological advances have made the fuel less of a human and environmental hazard. The most significant came about as a result of the race to the moon in the 1960s, which led to a better understanding of cryogenics and cryogenic storage with the expanded use of liquid hydrogen (-23€€€F) and liquid oxygen (-296€€€F). "Floating terminals"—located offshore—are another advancement that is still in the early stages of development. Both Shell and Texaco are considering implementing the technology, which, according to Lloyd's List, is both economically and environmentally viable.

LNG also is subject to numerous regulatory requirements. In addition to FERC and the Coast Guard, the National Marine Fisheries Service and the US Department of the Interior Fish and Wildlife Service, as well as numerous state and local agencies, have additional requirements.

Still, the bottom line appears to be that LNG has an excellent safety record, both at facilities and on tankers, as pointed out by Beale. Only three accidents have occurred at LNG facilities: The first (and worst) one occurred in 1944 at East Ohio Gas Company when a new tank failed as it was being placed in service, causing its contents to spill into the street and storm sewer system. (The tank had been built with a low-nickel content, which resulted in the spill.) A disastrous fire resulted, killing 128 people. LNG tanks today are constructed of stainless steel alloys, which were in rare supply in the 1940s as a result of World War II.

© 2008 Edison Electric Institute