LNG will be the "swing" supply source for natural gas in the US in coming years, according to a recent research report by Prudential Securities Inc., New York.
Growing US demand for natural gas is leading to increased concerns about near-term gas supply availability, and that concern has underpinned recent record gas price levels-more than $5/Mcf for average US spot and futures gas prices last week.
In this environment, traditional US gas supply sources from domestic production and Canadian imports may be insufficient to meet the increasing demand, Prudential Securities said, especially in the electric utility sector.
"Gas-fired power generation load in the US could increase by at least 3 bcfd by 2003 with the addition of new plants," the analyst said. Consequently, alternative sources must be found to fill the gap between the new demand and a declining supply base.
Hardly mentioned as a US gas supply alternative for some 30 years, LNG is again sparking the attention of the gas industry worldwide. Last year, there was a 100% increase in imports to the US (Fig.1), and plans are well under way for the reactivation of two existing US LNG terminals. On average, LNG can be delivered into the US at a clearing price of about $2.50/Mcf.
LNG trend bullish on gas
Growing US demand for natural gas, an excess of LNG supply worldwide, and improving cost efficiencies have all combined to improve LNG economics so much that it can be economically imported into the US for the first time in 20 years.
"In our view," said Prudential Securities, "the resurgence of the LNG industry is a bullish call on the long-term outlook for natural gas." Current and future prices could support LNG imports for at least 10 years, the analyst reports.
LNG producers are likely to target the US market because of the possibility of the normalized natural gas price threshold rising to $2.50-3.50/Mcf from the historical $1.50-2.50. Gas prices in the US are higher than normal, yet the price is competitive with global market alternatives indexed to crude oil. "Globally, the price of LNG is linked to crude oil in Asia and India, but spot prices are tied to the Henry Hub NYMEX [New York Mercantile Exchange] price in the US for natural gas, adjusted for basis differentials," Prudential Securities said in its report. But in the longer term, the NYMEX gas futures contract is likely to become the worldwide benchmark much as the price for West Texas Intermediate is the benchmark for global crude oils, the report continued. "In this regard, LNG markets in Europe and Asia would trade at either a discount or premium to the US benchmark, depending on local conditions," it said.
"However," the report added, "ultimately, electricity prices in the US may set the marginal price for LNG in the future as LNG's role as the supply for new gas-fired peaking generation plants increases. LNG projects will also compete against power projects and pipelines."
The current average clearing price for LNG imports into the US is about $2.50/Mcf, but the Gulf Coast area could receive LNG from the Caribbean for as little as $1.75/Mcf if producers there are willing to accept $0.50/Mcf for "excess gas that would otherwise be flared," Prudential Securities said. LNG from other sources would require a higher price to defray shipping costs but, based on the current NYMEX 10-year forward pricing curve of over $3/Mcf, costs would still fall within a reasonable range, making LNG imports economical whatever the source.
Several other factors contribute to the bullish outlook for LNG in the US:
- The demand for natural gas in the US is at an all-time high and is expected to exceed domestic supply for the next decade, "growing by at least 2% annually" (Fig. 1).
- LNG can compete successfully with US imports from Canada, because the terminal infrastructure is already in place, LNG technology and shipping costs are less than that for pipeline construction, and LNG supply is more geographically proximate. In fact, the Caribbean supply is 40-60% closer to the US East Coast LNG markets than is West Canadian gas.
- Deregulation in the US power generation industry is providing an incentive for new construction to meet electric power plant peaking needs. Approximately 90% of the new power capacity will use natural gas as its fuel because of the reduced environmental impact and the increased efficiencies and low capital costs associated with its use. Gas demand associated with electric power generation in the South Atlantic region is projected to grow by 11% in the next 10 years, and in the Mid-Atlantic region, by 36%.
- A growing liquid futures market for gas and power is likely to develop because of the price convergence between electricity and gas. The two will trade against each other (except on peak days), supporting an efficient market for gas in the coming decade.
- Regional LNG supply shifts and significant gas volumes discovered in areas such as Nigeria, Trinidad and Tobago, and Venezuela that have little domestic demand, are creating an LNG supply surplus.
- There is an excess of LNG receiving capacity in the US. Of the 1.4 bcfd of design capacity at the receiving terminals, about 75% currently is available.
- Costs for shipping and LNG facilities have been falling just as the price of gas is rising, so LNG projects can compete from a cost standpoint with equivalent-size gas pipeline projects serving the same markets.
LNG spot market
Because a significant amount of excess natural gas is being flared off the coast of Nigeria and in other areas where infrastructure is limited, a spot market has developed for deliveries to the US East Coast at attractive prices well below the current market.
Table 1, for example, illustrates the high-case and low-case scenarios for Caribbean LNG import economics.
Other factors are contributing to the movement of a spot market for LNG imports into the US, said Prudential Securities, including global deregulation of the natural gas and electric power generation industries, resulting in price and demand uncertainty for LNG producers.
In Japan, the world's largest LNG market, LNG sells for as much as $3.75/Mcf. However, even though the electric power production market there is opening to competition, none of the proposed new unregulated power projects are being planned with LNG as a fuel.
Meanwhile, in Europe, falling gas prices, deregulation, liberalization, and trading have decreased LNG margins.
However, LNG is gradually becoming more cost-competitive and its supply conditions more stable. Supply risks, for example, are decreasing due to political stability in the Pacific Rim and Atlantic Basin, and flexible international financing has contributed to more-reliable competitiveness with traditional energy sources.
Although the shipping of LNG remains costly-$0.50-1.00/Mcf-other factors are combining to lower the overall cost of using LNG. For example, new technology has reduced the development costs of gas liquefaction trains by over 60% from levels in the 1980s, Prudential Securities said (Fig. 2). Steam turbines have lowered the costs of liquefaction plant construction, and the larger trains have improved overall shipping economics.
Vessel availability growing
Demand for LNG shipping has increased with the emergence of the Atlantic Basin as an important market for LNG. Uncommitted shipping capacity is scarce; of the existing ships, only 11 are potentially available for trading in Trinidad and Tobago and Nigeria through 2000, and only 3-4 are available for spot market trades, according to the report.
Shipping accounts for 20-30% of the total delivered cost of LNG. This is because the vessel design, system, and materials are specialized for transportation of a product that must be kept at specific temperatures and pressures. In addition, they must have a large volumetric capacity to deliver LNG at specific gravity and density, and construction standards must be superior. The technology used to build the vessels has proven very reliable, but it also has been very costly. During 1975-80, the cost of an LNG vessel was about $350 million. Today, LNG vessels are being constructed for $160-165 million.
However, within the past few years, competition to replace existing LNG vessels with expiring charters has driven down the costs of new LNG tanker construction by 37%. And today, 21 LNG ships are on order at 8 Asian shipyards, most of them in South Korea (Table 2).
Because current capacity is so scarce, some new LNG ships are now being built worldwide on a speculative basis, which is a startling departure from historical LNG trade that typically required "a full chain of commitments" before orders for ships were placed.
Previously, long-term, 20-year supply-purchase agreements had to be in place before LNG vessels were built. Frequently, the LNG tankers were even included in financing of the liquefaction plants.
For ships to be built on a speculative basis, there must be a tremendously reliable supply of gas available and an equally reliable market for it. The global LNG surplus is the impetus for the speculation, and the US spot market alone could require up to 300 shipments/year when four US import terminals are operating in 2002. Other worldwide current and future LNG markets are shown in Fig. 3.
US import capacity increasing
Previously, in addition to high delivery costs, a serious limitation to LNG deliveries to the US was constrained import terminal capacity. Until recently, LNG was used primarily as a supplement to winter peak-demand periods, and, in 1999, LNG imports represented less than 1% of total US gas demand. But, in 1999, US imports of LNG nearly doubled to 163 bcf from 85 bcf.
With LNG costs now more competitive, two LNG terminals in the US are being returned to service to accommodate increased deliveries. The Williams facility (formerly owned by Columbia Energy Group) in the lower Chesapeake Bay area at Cove Point, Md., and El Paso Energy Corp.'s terminal at Elba Island, off Savannah, Ga., are being reconditioned and upgraded. Both are scheduled to be in service in 2002.
Two other LNG import terminals currently are in operation in the US-the Tractebel terminal (formerly owned by Cabot Corp.) in the Boston harbor at Everett, Mass. (which received about 100 bcf of LNG last year) and the CMS Energy Corp. terminal at Lake Charles, La. (60 bcf in 1999). With the addition of the two terminals being restored, the US would have a send-out capacity of 2.7 bcfd in 2002.
Although modest expansions could increase that total to 4.5 bcfd, the total send-out capacity of the four plants would still represent less than 10% of the North American gas market and "likely 5% of that same market 10 years from now," Prudential Securities said (Table 4).
The Lake Charles terminal, now the country's largest operating LNG facility, is currently underutilized and holds commitments with only one supplier for long-term firm capacity. But it has already booked a record 41 LNG cargoes for 2000 (up from 38 in 1983), and the terminal has a capacity for expansion as the market grows; It can receive as many as 100 cargoes/year.
In June, major shippers awarded the Cove Point facility three 20-year contracts for 250 MMcfd each. Williams is spending $150 million to reactivate the terminal, which has a capacity of 1 bcfd and, when ready for operation, will be the country's largest LNG receiving terminal.
El Paso Energy is spending about $25 million to reopen the Elba Island facility, which will receive initial LNG shipments from Trinidad.
New supply sources
To date, the US market has received spot LNG supplies from Abu Dhabi, Qatar, Malaysia, Australia, and Algeria (Table 3). Nigeria, Venezuela, Egypt, Yemen, and Angola may also supply LNG to the US in the future.
Also, legislation is pending in Alaska to provide tax incentives for a possible gas pipeline and/or LNG export project to deliver gas from Alaska's North Slope to markets. Yukon Pacific Corp., Anchorage, has been working on one such project for almost 2 decades, according to the Prudential Securities report. Yukon Pacific plans to construct a liquefaction plant and export terminal at Nikiski. An associated 800-mile gas pipeline southward from Prudhoe Bay to Nikiski also is under consideration. (OGJ Jan. 31, 2000, p. 74, and OGJ Online, Mar. 3, 2000).
Meanwhile, the Atlantic LNG facilities in Trinidad will supply the most competitively priced LNG supply to southeastern US markets. Not only are its liquefaction facilities economical and efficient, but its proximity to the US is most advantageous, Prudential Securities contends. It only takes 11 days round trip from Trinidad to Elba Island vs. a 20-day round trip from European sources.
Furthermore, Trinidad and Tobago currently boasts proven gas reserves of 21 tcf, which are expected to grow.
In addition, the Trinidad and Tobago government in February approved expansion by a second and third train, which will add 1 bcfd of liquefaction capacity to the LNG complex at Port Fortin, Trinidad.
The first train was an $800 million project sponsored by then-BP Amoco PLC and BG, which supply gas from fields off the eastern and northern coasts of Trinidad. The first train supplies Spain with 40% of its output and the Everett LNG terminal with 60%. Train 2 is scheduled to begin shipments in fourth quarter 2002, at which time the Elba Island terminal will be ready to receive LNG.
Combined production from all three trains is expected to be 10 million tonnes/year of LNG. With completion of the third train, Trinidad and Tobago would rank sixth among the world's largest LNG exporters, behind Algeria, Indonesia, Qatar, Malaysia, and Australia.
Trinidad is looking at the fourth and fifth trains, "most likely in a partnership with Latin American producers," reported Prudential Securities.
Partners in the Atlantic LNG project include BP, BG, Repsol-YPF SA, Tractebel SA (which acquired Cabot's LNG business this summer), and state-owned NGC Trinidad & Tobago LNG.
Venezuelan LNG supply may be slow to enter the market, if at all, even though it has announced two projects, because of political and legal concerns that give crude oil development priority, Prudential Securities contends. However, the new government in Caracas has placed a special emphasis on development of Venezuela's natural gas sector, focusing on value-added export-oriented, natural gas-based projects.
Enron Corp.'s José LNG project has a long-term, take-or-pay supply contract locked in with state oil company Petroleos de Venezuela SA (PDVSA) for 350 MMcfd. The José terminal, planned for start-up in late 2003, will have a single train with capacity of 2.1 million tonnes/year. The market targeted for this LNG would be industrial customers along the Texas Gulf Coast.
Another, even larger project, Venezuela LNG, is planned for start-up in 2005 with a single train delivering 4 million tonnes/year of LNG produced from gas fields in the Gulf of Paria off Venezuela. PDVSA owns 33% of the project, with the balance held by Royal/Dutch/Shell, 30%; ExxonMobil Corp., 29%; and Mitsubishi Corp., 8%.