Understanding Risks Associated with LNG Importation in the U.S.

March 2004
Project Finance International
Hendrik Gordenker, Troy Alexander

It is often said that risks create opportunities, but what about the risks created by opportunities? Much has been written about the tremendous opportunities in the U.S. liquefied natural gas (LNG) market, but less about the associated risks.

Setting up an LNG supply requires creating a supply chain that connects remote natural gas reserves to the end-user. If any link is disrupted, then all participants in the chain, as well as their respective creditors, face serious risks. The swings in pricing in the huge U.S. natural gas market create additional risk. LNG supplies will always have to compete against domestic gas sources. Natural gas prices have been relatively high recently, and many experts predict that they will remain high. However, gas prices have defied past forecasts, and if they fall low enough sales revenues may not cover the significant operating and financing costs in the long LNG chain.

The challenge for the introduction of LNG in the U.S. is to find ways to allocate those risks to the parties best able to mitigate and bear them. That risk allocation will need to be adapted to the circumstances of each project. Without it, financing will be a challenge.

Market Potential
Rising demand for natural gas, shrinking U.S. gas reserves and increasing production costs, and continuing geopolitical concerns about stable oil supplies have drawn attention to LNG imports into the U.S. for the first time in nearly 30 years. Use of natural gas in U.S. electric power production has increased almost 40 percent in the last decade, while domestic natural gas production declined by four percent. And while the U.S. ranks sixth in the world in natural gas reserves, it supplies only 3.3 percent of the world’s natural gas supply, even as the nation consumes more than 25 percent of all natural gas produced.1

Environmental concerns also drive the marketplace. Natural gas is the cleanest burning of all the fossil fuels, making gas-fired power plants easier to site close to energy-hungry cities. And improvements in combined cycle gas turbine power generators have led to increasing levels of thermal efficiency, reducing both fuel consumption and emissions.

These trends lead to recent projections envisioning LNG imports more than quadrupling by 2010, bringing approximately 2.2 trillion cubic feet of LNG into the country annually.2

Responding to dwindling domestic reserves, U.S. regulators recently loosened rules related to access to LNG terminals. In the past, the Federal Energy Regulatory Commission (FERC) required that LNG terminal facilities be open to third parties for a fee set by the operator, much the way interstate gas pipelines and toll-roads work. Now FERC will allow at least some terminal operators more freedom as to who has access and at what cost, increasing terminal profitability. FERC’s new policy allows LNG suppliers to (i) use the entire capacity of an LNG import terminal, free of open access requirements, and (ii) charge market-based rates for LNG terminalling services. However, this policy may not apply if the LNG terminal has market power in the market it serves.

Understanding the LNG Supply Chain
To go from extracting the natural gas from a source country such as Indonesia or Qatar to delivering it to the end-user in the U.S. is a complicated process, requiring the participation of multiple entities. The accompanying chart illustrates the links in the LNG chain connecting upstream gas reserves to end-users:

THE LNG SUPPLY CHAIN

*Extraction and liquefaction are usually built and financed as one integrated project.

A typical LNG receiving terminal has a daily send-out capacity of one billion cubic feet of gas, at a construction cost of approximately $500 million to $1 billion. Shipping requirements may involve five to 10 vessels costing around $155 million each, while an upstream gas production/liquefaction complex costs between $2 billion and $10 billion, depending on size and location. All told, as much as $200 billion in worldwide investment will be needed for LNG to reach full potential.3

More than 40 new LNG terminals have been proposed for construction in North America by 2010, although most of these will probably never be built. Developers are targeting locations, onshore and offshore, near large markets that are distant from domestic reserves (such as the Northeast) and locations with good access to transportation capacity (such as along the Gulf Coast). Given the potential difficulties of locating a terminal in the U.S., resulting from relatively strict environmental scrutiny and frequent local opposition, some developers have selected sites outside of U.S. territory but with access to the U.S. grid such as the Bahamas or Mexico.

A Different Price and Volume Environment
LNG initially took root in Asia, but the U.S. market presents a fundamentally different price and volume structure from Asian markets, where power and gas utilities ramped up imports of LNG during the energy shortages of the 1970s. These buyers were willing to enter into take-or-pay contracts to provide the new LNG suppliers a stable source of revenue to support financing. Under these contracts, the buyer agreed to pay for a specified minimum certain quantity of LNG annually, whether or not the buyer was able to take that quantity (however, buyers had certain rights to make up quantities paid for but not taken). The LNG price was linked to crude oil prices, and often had an "S-curve" mechanism to maintain prices generally within an agreed band in order to protect the respective parties from the impact of extreme volatility in crude oil prices. Asian utilities were able to absorb the risk of take-or-pay because of rapidly growing demand. Also, these regulated utilities were able to pass fuel costs through to their consumers, so they could accept that the LNG price would fluctuate with oil prices and possibly diverge from oil prices through the S-curve mechanism.

The LNG market in the U.S. is developing using several distinct models. For example the Cove Point LNG terminal in Maryland is being developed based on long-term take-or-pay contracts, while others are being developed as merchant plants. One or more of the major oil companies will likely build plants, either for their own use or with a merchant component. Traditionally, however, the U.S. market has been based on short-term contracts and spot pricing. Marketers trade much of the natural gas sold in the U.S. market, and physical delivery takes place using pipeline capacity purchased on open access pipelines. Natural gas prices thus fluctuate based on gas market supply and demand, not crude oil prices. This poses a challenge because each entity in the LNG supply chain has inherent expenses associated with production and delivery, and those costs remain fixed no matter the market price, including when LNG prices fall below the cost of bringing it to market.

Who will bear this risk? As a consequence of disaggregation in the U.S. gas market, developers of LNG receiving terminals may be able largely to avoid it. The business model many terminals are contemplating is to charge a toll based on throughput or capacity reserved under long-term contracts, so terminal revenues are uncoupled from U.S. gas prices. LNG producers, eager to get their LNG to market, have in a number of cases taken price risk, by agreeing to sell LNG at netback prices keyed to U.S. gas market prices. However, U.S. LNG importers, terminal operators and lenders understand that producers cannot remove all of the risk. Based upon the estimates of some experts, if U.S. prices dive to the $2 per MMBTU level again, LNG suppliers’ margins will be cut and they may even be unable to recover their substantial costs. This situation is not tenable over the long term and LNG suppliers are likely to seek relief.

Force Majeure
The risks flowing from an event of force majeure are particularly difficult to allocate. Force majeure is by definition uncontrollable and often excuses the non-performing party from liability. Where force majeure interrupts an LNG chain, the stranded facilities of the LNG chain may be without throughput and without recourse for contract breach. For example, if an LNG receiving terminal is forced to shut down for reasons beyond its control, the entire chain is disrupted. The LNG production facility and ships remain fully operational, but may be unable to supply LNG to the terminal or alternative markets. Yet, the producer may still be obligated to honor contracts with clients and creditors.

The use of force majeure clauses in contracts, in theory, can help mitigate this problem. However, once the supply chain is disrupted it may take several months to get back on track, depriving lenders of revenues needed for debt service, eroding equity returns, and potentially exposing parties to liability for non-performance if force majeure provisions are not back-to-back.

Tailoring Project Structures and Financing to Risk
In addition to the volume, pricing and force majeure risks discussed above, other issues to consider include:

• LNG receiving terminals, especially in the U.S., are vulnerable to construction delay from regulators or organized local opposition. As long as thirty years ago, local residents were able to thwart LNG receiving terminal plans in California. This uncertainty can play havoc with development and financing of other links in the LNG chain.
• More generally, coordinating the financing of the interconnected links of the LNG chain is a challenging undertaking. Great effort goes into creating conditions precedent, start-up windows, information provisions and other terms in project contracts that enable coordinated development of the chain.
• Contract provisions covering breach present another challenge. These provisions may include liquidated damages provisions and security arrangements for project revenues. If a party is unable in fact to bear a risk, no matter how strongly the contracts are drafted to impose the risk on that party, this risk may remain unresolved. Thus, in negotiating project and financing documentation, the parties need to keep the commercial realities of their risk allocations clearly in focus.

The landscape for developing receiving terminals in the U.S. is dramatically different from that presented by traditional LNG projects. The parties are different, the markets are different and the risks are different, so new ways of allocating and balancing risks are required to attract sponsors and lenders. While there are no easy answers to mitigating risk, by taking a careful, tailored approach to allocate risks to parties best able to bear them, LNG projects in the U.S. can also yield significant rewards.

About the Authors
Troy Alexander is co-head of the Energy, Infrastructure and Project Finance practice at White & Case LLP, a leading global law firm that has handled more than 23 LNG transactions in the past two years. He can be reached at . Hendrik Gordenker heads White & Case’s LNG practice group in Asia. He can be reached at .

Endnotes
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“The Next Prize,” Daniel Yergin and Michael Stoppard. Foreign Affairs, November/December 2003, pages 105, 109, 110.
“Lower Costs Help Boost United States LNG Trade,” Larry Persily. Petroleum News, January 4, 2004, page 9.
Yergin and Stoppard, page 105.