To better understand the evolving outlook for LNG and its role in the U.S. gas market, Fortnightly assembled a group of LNG specialists with various perspectives on the issues.
LNG as Price Taker
And its impact on power generation.
by FERC exempts such facilities from open access and non-discriminatory operations, which has resulted in the utilization of cryogenic storage to avoid receipt of spot cargoes of LNG. Loss of spot LNG will reduce the demand for conventional storage of regasified LNG, and will increase the competition between cryogenic gas and conventional storage gas to capture short-term peaking demand. An offsetting factor might be that less spot base-load LNG gas will be competing for seasonal price differentials with conventional storage gas.
LNG Will Be a Price Taker
On a full-cycle cost basis (accounting for exploration, development, and production costs), LNG costs delivered to the regasification facility, also called the commodity, insurance and freight (CIF) cost, from many liquefaction sources presently are competitive with existing production from many traditional North American supply basins. Global Energy research indicates that regasified LNG, even from the most expensive and distant supply regions, has the potential to displace incremental Gulf of Mexico onshore and offshore production on both a full-cycle replacement-cost and on a marginal-cost basis.
Our research indicates that incremental indigenous GOM non-associated gas has a full-cycle replacement cost of $2.75 to $3.75/MMBtu—well below current market price. In comparison, regasified LNG has a full-cycle replacement cost ranging from $2.25/MMBtu to $2.75/MMBtu for the Caribbean to Gulf of Mexico, to $3.35/MMBtu to $4.15/MMBtu from Australia, Middle East, or Norway to GOM, based on wellhead net-back prices of $0.30/ MMBtu to$1.30/MMBtu.
Marginal cost is defined as the total full-cycle recovery cost (export wellhead to long-haul import pipeline) minus fixed capital cost (return on equity and cost of debt). The marginal cost of in-digenous gas from the GOM generally is 65 percent of the total cost into the interstate pipeline, compared with regasified LNG supplies at 50 percent. Marginal costs for the GOM are $1.80/ MMBtu to $2.50/MMBtu, compared with regasified LNG at approximately $0.90/MMBtu from the Caribbean to $1.75/MMBtu from Australia.
The market price of LNG is a contractually determined surrogate for the energy cost for the import country, except for Europe and the United States, with existing international trade on pipeline gas. The market price is tied to the competing power fuels, usually oil (both crude and products) and now coal, as seen by recent Indian and Chinese transactions. For the United States, liquefied gas will compete directly with indigenous pipeline gas. Even long-term contracts for base-load LNG supply have been tied to the short-term NYMEX market. A traditional long-term price structure based on discrete investments for upstream infrastructure has not yet been offered to U.S. “anchor” customers.
One misperception is that at some price level, LNG will flood into the North American gas market and set a cap on indigenous pipeline gas. This price level is based on the fact that the marginal cost—and for many of the downstream U.S. markets—the full-cycle cost of regasified LNG is less than into-pipeline marginal cost for incremental gas. This perception lacks an appreciation of the difference between cost-of-service and net-back pricing, as well as the role of competition in disciplining prices, particularly the asymmetric application of market competition for