There has been suggestion the U.S. import ‘cheap’ (i.e., nearby supplies priced at variable cost) LNG into the U.S. as a way to apply downward pressure on domestic natural gas prices. However, The U.S. will not be able to attract substantial volumes of spot LNG because there is little supply not committed to firm European and Asian contracts through 2005. Potential spot supplies, given distance from the U.S. and technical constraints at several U.S. regasification terminals, are unlikely to be significantly less expensive than marginal local production.

New Era in Natural Gas Pricing
Natural gas prices in the U.S. have risen to a level attractive to LNG imports since early 1999. As Figure 1 shows, gas prices must rise above $3.00/MMBtu to attract significant incremental volumes of LNG to the U.S.

Global Gas Supply/Demand Balances
The global supply/demand balance for LNG is pretty tight. In 2003 average utilization of nameplate capacity for liquefaction facilities was 87%, but ranged from 99% in Brunei to 20% in Libya (see Figure 2). In early 2004, the explosion at Skikda, Algeria tightened the market by 670 MMcfd (5.1 MTPA), but Sonatrach has been able to make up some of the loss by increasing run rates at their Arzew facility. Thus global supply (without Skikda) has about 2,200 MMcfd of spare capacity. However, as will be shown, there are a number of infrastructure issues likely to constrain send-out capacity at U.S. regasification terminals below the nameplate capacity of 2,700 MMcfd.1

In most LNG markets, supply is secured via long-term off-take contracts and the U.S. is no different. As seen on the left side of Figure 3, over the past four years, 75% of LNG imports have been under long-term contracts. About half (100 MMcfd) of spot volume in 2002 was from an early start-up of Trinidad II in the fourth quarter; volume that disappeared when the long-term contract with Engas (Spain) took effect in June 2003.

Because of the regulatory structure of European gas markets in the past, regasification developers had the financial ability to back signing long-term firm supply contracts. Demand conditions (e.g., mild weather, slow economic activity) in Asia and Europe play a key role in determining supply availability for the U.S. The right side of Figure 3 shows that demand conditions allowing Europe and Japan to release cargoes for spot sale in the U.S. are typically in the spring and summer.

A Price Differential is Rarely Sufficient to Divert Cargoes to the U.S.
LNG projects in Asia and Europe traditionally have been integrated with a consortium of producers and consumers sharing profitability and risk across the entire value chain. Thus off-take agreements at regasification terminals have been for 10-20 years at fairly stable volumes. There usually were no competing supplies (e.g., no pipelines or indigenous supplies) so a long-term contract did not force the gas marketer to forego other supply options. The project also was selling into a tightly regulated (and physically short) market so delivered LNG prices into Asia and Europe tended to be higher than in the U.S. (see Figure 4). As long as LNG pricing in Asia and Europe continues to be on an oil basis (crude in Asia and residual fuel oil in Europe), high crude oil prices should prop up delivered prices to all three markets.

Since 1999 delivered LNG prices to Europe dropped below U.S. import prices for two reasons. First, U.S. gas prices have risen not only in absolute level, but also have moved closer to crude parity. More importantly in Europe as power generation (predominantly in southern Europe) continues to reduce its use of residual fuel oil its price relative to crude declines.

A simple positive price differential in the U.S. is rarely sufficient to divert cargoes. At prices below $3/MMBtu, only Trinidad is close enough to deliver spot volumes to the U.S., pay for transportation, and realize a positive netback. However, a spot cargo from Trinidad to the U.S. can be accommodated only if Spain (the likely delivery point the cargo was diverted from) does not require its next firm contract delivery for 25-30 days (10-12 days to/from U.S. plus another 15-18 days to Spain). As Figure 5 shows, the sailing time and shipping costs for liquefaction facilities farther away than Trinidad make spot deals into the U.S. even tighter to fit into firm contract obligations.

LNG producers often restrict resales to alternative markets so attracting spot cargoes to the U.S. depends on more than the Henry Hub price. However, even with destination flexibility, a tight shipping market makes proximity to markets critical in value creation for the LNG producer. LNG projects currently control 60% of the tanker fleet making it difficult for merchant regasification owners to find vessels for spot chartering. Although a shortage of spot LNG charter vessels is likely to continue for the foreseeable future, the increase in tonnage controlled by ship owners, oil and gas companies, and LNG buyers (about 50% of capacity on order) might improve prospects of a more flexible market that facilitates short and medium-term trading (see Figure 6).

Contractual and Technical Issues Limit Spot cargoes to U.S. Terminals
In 2003, 92% of U.S. regasification capacity was controlled by major (upstream) gas companies. Smaller spot (merchant) players have to work with long-term capacity holders to secure necessary logistical arrangements to complete short-term deals. One form of collaboration is a merchant trader securing access to regasification capacity and infrastructure if the merchant signs contracts with an international gas player’s (preferred) liquefaction affiliate. Some announced regasification terminal projects sponsored by merchant players may be running into similar constraints given their apparent difficulty in securing supply contracts.

Technical issues surround physical characteristics of an LNG cargo from a specific liquefaction facility to a specific regasification terminal. The heat content of LNG can range between 1,000 and 1,162 Btu per cubic foot (Figure 7). High heat content is incompatible with many U.S. appliances and industrial processes. Thus major interstate pipelines have a heat content specification of 1,035 Btu per cubic foot, with a range of plus or minus 50 Btu.

On a spot basis, only three operating liquefaction facilities (Trinidad and Skikda, Algeria in the Atlantic Basin plus Alaska in the Pacific) produce LNG with a heat content within current U.S. gas pipeline quality specifications. Given that all four U.S. regasification terminals are in the Atlantic Basin and assuming Skikda is not operational, there is about 150 MMcfd of spare liquefaction capacity meeting U.S. natural gas specifications. Nitrogen or air injection processes diluting higher heat content cargoes at Everett and Cove Point allows the inclusion of spare capacity in Nigeria (100 MMcfd) and Qatar (100 MMcfd). So of the 2,200 MMcfd of spare liquefaction capacity in the world, at best 350 MMcfd (15%) could meet current U.S. quality specifications. 2

In addition to heat content restrictions, a number of other issues restricting throughput at regasification terminals below peak send-out capacity are listed in Figure 8. Some of these issues are the more binding constraints on delivering a spot cargo, but also the hardest for which to estimate the commercial impact.

The likelihood that LNG will be a “cheap” source of supply in the future is remote. With the natural decline of domestic production, increasing volumes of LNG will be necessary. As seen in Figure 9, the cost of new sources of LNG (based on full-cost economics) will be of the same order of magnitude ($3.50 – $5.00) as pipeline gas from the Mackenzie Delta in Canada or the North Slope of Alaska. Capital recovery imbedded in full-cost economics is only one reason why LNG will be among the more expensive new sources of natural gas. Another reason is that the new supply sources will be thousands of miles away from the U.S. (e.g., Norway or Qatar).

There is little hope the U.S. is able to import “cheap” LNG into the U.S. as a way to put downward pressure on domestic natural gas prices. Recent trends indicate Henry Hub prices must exceed $3/MMBtu to make it commercially attractive to bring spot LNG cargoes into the U.S. However, given the tight supply/demand balance in the U.S., current U.S. LNG regasification effective capacity is unlikely to deliver incremental volumes sufficient to displace the need for natural gas to price high enough to encourage demand conservation sufficient to balance the market.

1 LNG volume is typically measured in billion cubic meters. However, this paper measures volume on a daily basis to reinforce the notion that “cheap” LNG cargoes need to be delivered on a ratable basis to have a sustained impact on U.S. natural gas pricing.

2Heat content not only is an issue for current spot cargoes, but for growth in LNG imports as well. The FERC held a public conference in February 2004 on the appropriateness of current gas quality specifications and the potential need to initiate rulemaking on the subjecti>