LNG, or liquefied natural gas, that previously embarrassing relic of the 1970s, has been poised for a comeback in the US for much of the last decade. A measure designed to reduce the dependence of the United States on fuel oil and meet tightened standards for emissions proved eventually too expensive to survive the 1980's. Much like some of the cultural detritus of the decade, the new improved LNG facility enjoyed a resurgence in popularity alongside an increase in natural gas-fired capacity in the last five years.

Several receiving facilities and regasification plants emerged from mothballs and were snapped up by merchant players such as Tractebel, Shell, CMS and El Paso. LNG technology also has to bear the burden of Latin American countries' desire to become gas exporters. The rich US market, the thinking went, could provide the offtakers to make gas pipelines and gasification facilities financeable.

But while the technology for producing LNG has improved immensely in the past few decades, there is still a gap between its production costs and those of piped gas from elsewhere in the region. Can a costly (circa $2 billion) receiving facility be financed and pay its debt when subject to the fluctuations of the Henry Hub natural gas price?

In a sense, the fact that Americas LNG cargoes are priced off the US gas benchmark is a positive sign. Until recently its value could usually be expressed as a derivative of the Japanese crude oil import price ? a reflection of the role of gas as a displacer of oil in Japan and Japan's pre-eminent role as a customer. With this increasing sophistication came the development of an intermittently lucrative spot market in the region.

The spot market in the Atlantic basin is in turn driven by the merchant power market in the United States, which is where the current difficulties crop up. Henry Hub gas prices have fluctuated between $2 and $3.80 per million British Thermal Units (BTU). As Project Finance went to press this figure stood at around $3. Indications are that few of the integrated merchant energy players have captured much revenue from the limited spikes this year.

Price pressures

Chris Ellsworth, consultant at Pace Global Energy, reckons that a price holding above $3.20 should make LNG projects viable. He points out that the South California market price would be about 15 cents higher. ?Plants were mothballed after the eighties after the end of regulated prices,? he says. ?In those days you could get above $8 per million BTU. But nowadays on the supply side, I think there are doubts about the ability of the US producers to come up with sufficient supply to match demand. There could be a 307 million cubic feet per day market by 2015, and producers will find it hard to get there from the current 197 million cubic feet level.?

A report from Standard & Poor's analyst Peter Rigby bears this analysis out. He noted that recent drilling activity in the US, while at a record level, has produced fewer and smaller finds (see Project Finance's Oil & Gas Report, December 2001). The fundamentals for the construction of new LNG facilities, therefore, do exist.

The difficulty, however, given the market structure that prevails in the US, is to make gasification and regasification terminals financeable. Merchant LNG equipment has about as much allure to lenders as a merchant power plant in the current environment. Even a tolling-style agreement, whereby a facility eliminates any mismatch between supply and demand, comes up against problems with demand fundamentals and toller credits.

One such natural customer, Williams, has demonstrated the difficulty in relying on tolling agreements for credit support, as bonds backing construction of AES Ironwood and AES Red Oak have sunk below investment grade along with the Williams rating. Indeed, Williams has sold its Cove Point terminal to Dominion Resources for $217 million.

Cove Point has a capacity of five billion cubic feet and is located on the western side of Chesapeake Bay in the mid-Atlantic region of the US. At present it is used primarily as a gas storage facility, but planned capital expenditure would bring it back into its primary use as an LNG receiving station, and increase its capacity by 2.5 billion cubic feet. According to a statement, both the current and future capacity has already been taken up.

Shell Gas & Power has bought all of the capacity at the El Paso affiliate Southern LNG's Elba Island terminal expansion. Elba is located near Savannah, Georgia, close to the growing electricity load pockets of the southeastern US. Shell beat out three other bidders for the 3.3 billion cubic feet of capacity. This 30-year agreement comes into force in 2005. Elba has been mothballed since 1982, should become active this year, and has gained an attractive anchor tenant in Shell. Although the InterGen joint venture with Bechtel looks set to enter a period of consolidation rather than expansion ? the Coral Energy unit is now one of the only highly-rated marketing operations in the US.

The final large LNG facility, and the earliest to come back into operation, is Tractebel's Cabot LNG terminal. This plant has been very profitable while capacity constraints and new gas-fired capacity have kept prices high in the northeast. The only serious worry for the owners is that wholesale power prices might continue to soften. A threat by the mayor of Boston, where Cabot is located, to shut down LNG shipments, has had little practical effect.

Around 80% of the US coastal capacity, therefore, is taken up, and it remains unclear how existing users will optimise their capacity. BG took a large bet last year by buying up 80% of the capacity of CMS Energy's Lake Charles LNG terminal. The agreement runs through 2005 and enabled CMS to secure $305 million in financing in December 2001 for an upgrade of the facility. BG is looking at Egyptian and Indonesian sources. In Egypt, it signed an agreement with the Egyptian General Petroleum Corporation (EGPC) and Edison of Italy for an integrated LNG export project. Project company Egyptian LNG will build, own and operate a proposed liquefaction plant with a first train set to come onstream in 2005.

Paria ? the semi-Colon

This is not the news that backers of the Paria project want to hear. Paria is a scaled-down and relaunched version of the Christobal Colon project, which has been in planning since the first signs of recovery in the US gas market. Shell is again the prime mover in this scheme, both as a developer of the Paria LNG terminal and the associated gas fields, located off the coast of Venezuela.

Its partners have been a varied group. ExxonMobil has declared an interest and Mitsubishi is involved, largely as a supplier. The main question for bankers is the extent of Petroleos de Velezuela S.A. (PDVSA)'s stake in the operation and, in turn, the extent of Venezuelan government over PDVSA. A near-coup in the country and a series of downgrades on outstanding heavy crude oil project bonds will not have improved comfort levels. In January 2002, PDVSA increased its stake from 33% to 60%.

Paria would be a 4 million ton-per-year train, with prospects for further additions. The project also calls for the construction of a $1.2 billion liquefaction plant at Guiria, and is designed to extract additional value from the Deltana and Mariscal Sucre offshore projects. Natural gas reserves in the Deltana Basin could total 38 trillion cubic feet, according to PDVSA estimates.

Mariscal Sucre has reserves of about 10 trillion cubic feet, and would be the primary supplier of the Paria project, since Shell and Mitsubishi are the main foreign sponsors. The joint venture agreement would cover both, and should be signed in 2003. New reserve drilling will also be a part of the project.

At present the sponsors are continuing discussions with Qatar Petroleum (QP) to participate in the project. These talks began in February 2002, although there has been no firm announcement. QP has already signed an agreement to supply LNG from Qatar to ExxonMobil's UK operations.

The SoCal experience

The hopes of Latin American exporters, primarily Bolivia and Peru (through its much-delayed Camisea development), wait on the prospects for importation to Southern California, where the spread over Henry Hub prices is tempting. Most new capacity in California is gas-fired, and pipeline capacity is currently constrained. Even the expansion in the Kern River pipeline system (see Project Finance, June 2002, p.12) will not take care of all projected demand.

Since the Californian populace appears opposed, despite the energy crisis, to approve large LNG facilities, one popular solution has been to land LNG in the Baja California region of Mexico. Baja is interconnected more with California that with the rest of Mexico, and it is here where it may be possible to find a chink in the monopoly of state gas producer Pemex.

Indeed, El Paso and Phillips have developed plans for a regasification plant in the area with the intention of supplying California. But, according to the agreements signed between the two sponsors, the 4.8 million tonnes per year would be supplied largely from Phillips reserves located in the Timor Sean between Indonesia and Australia. A liquefaction plant planned near Darwin will handle Phillips' supply obligations.

El Paso, this time in conjunction with Shell, is also developing a regasification terminal on the eastern coast of Mexico, with a 10 million tonnes per year capacity. The scheme, announced last year, has apparently gone ahead with the blessing of the Mexican Energy department, and Pemex will be the sole offtaker. This fits in with the current constitutional status of Pemex, which is sole distributor, but can accept private sector participation in ancillary roles.

Atlantic entreaties

The Americas project with the most consistent financing record has been the Atlantic LNG facility and its associated infrastructure in Trinidad. Atlantic LNG, whose shareholders are BP, BG, Tractebel, YPF-Repsol and the state-owned Natural Gas Company of Trinidad and Tobago, is the fifth largest global LNG exporter.

A first train was financed through a $600 million loan in 1997 and constructed in 1999, and work is now over 30% complete on a two-train expansion. Whilst the project has a formal joint venture agreement and has signed an engineering procurement and construction (EPC) contract, there is every indication that the sponsors will prefer to keep the facility going with equity infusions.

Not so some of the associated work, however. Citigroup is in the process of finalising a $41 million bond issue for Phoenix Park Gas Processors, which processes the natural gas produced in the Trinidad fields. The most significant aspect of the issue is that, while dollar-denominated, it will be sold into the domestic capital markets ? a project first. The bonds will rank pari passu with a$110 million issue led by CSFB and Citibank in May 1998.

The new issue supports construction of a new fractionaliser that will produce butane, propane and other byproducts from the additional liquids from the Atlantic LNG expansion. Most of the output from the plant will be sold onto the Gulf coast of the US, although the Brazilian market, which still demonstrates robust growth in demand for such products, also remains a possibility. The bonds have priced, although this figure has not been released, and have a maturity of 2015.

LNG producers appear to be locked into a very nuanced stalemate with pipeline producers. Of the many proposed facilities in the region, bankers are keenest on the potential for the Baja California plans, especially after Marathon (with a sizeable stake in the Asian Sakhalin project) has explored the area. Others are viewed with severe scepticism. Most would be much more comfortable financing a pipeline in the US, and few show much sympathy for Latin American efforts to improve their export base.