Significant price increases at all markets in the lower 48 States occurred during the report week, as some positive economic news suggested that demand for energy commodities may be recovering. During the week, reports from the U.S. Department of Commerce showing improved retail sales and a report from the Federal Reserve showing improved levels of industrial production likely were factors in the improved outlook. While many spot prices for natural gas are still trading at roughly half of their levels at this time last year, significant price increases this report week suggest that the year-long trend of declining prices may be coming to an end. Prices at the Henry Hub increased 56 cents per MMBtu, or about 21 percent, since last Wednesday, September 16. Furthermore, price at the Henry Hub has gained $1.44 per MMBtu since September 4, when the Henry Hub price averaged $1.84 per MMBtu. Increases in other markets in producing zones along the Gulf Coast, such as Houston Ship Channel in East Texas and Transcontinental Gas Pipe Line (Transco) Station 65 in Northern Louisiana, ranged between 18 and 22 percent on the week.
The largest price increases in the lower 48 States since last Wednesday occurred at markets in the Rockies and California, where temperatures were generally above normal. Increases in weather-related demand for natural gas as a fuel for power generation in California likely contributed to the price at the Pacific Gas and Electric Citygate increasing 70 cents per MMBtu to $4.02. The Southern California Gas Citygate price increased by 76 cents per MMBtu to $3.74, trading at a 46-cent premium to yesterday's Henry Hub price.
Although average gains in the Northeast region were less than gains in western parts of the country, increases were still substantial. During the report week, the average price at Transco Zone 6 increased by $0.55 to $3.58 per MMBtu. Temperatures in the Northeast were cooler than previous weeks with highs only in the mid-70s, likely limiting upward price pressure relative to markets in the West. The Northeast generally experiences the highest prices in the country (outside Florida during the summer), partly because of pipeline transportation costs for deliveries from the Gulf of Mexico region. However, price differentials between the Northeast and Gulf of Mexico tend to be lower during times of low demand. On Wednesday, September 16, the average spot price for delivery in New York off Transco reflected a premium of 30 cents per MMBtu to the price at the Henry Hub. This low differential, which can increase to well above $1 or $2 per MMBtu in the winter, indicated very low demand in the region. Spreads between Northeast prices and prices in other markets also suggested evidence of increased supply options for the region, such as the new access to Rockies supplies in Ohio through the Rockies Express Pipeline (REX.) Many prices in the Northeast during the report week were lower than prices in California, which is unusual even for this time of year.
Along with significant increases in the forward prices for a variety of commodities, including the crude oil price, natural gas futures this week continued to move higher. The price of the October contract increased by 93 cents during the report week to $3.76 per MMBtu, which is the highest price for the near-term contract since the beginning of August. However, compared with the expiration price of October contracts from the previous 2 years, the difference in price for this year's October contract is still stark: the October 2008 and October 2007 contracts expired at $7.47 per MMBtu and $6.43 per MMBtu, respectively.
The price of the 12-month strip, which is the average for futures contracts over the next 12 months, increased by $0.63 to $5.42 per MMBtu since last Wednesday. Beginning with the near-month contract, futures prices increased sharply through the beginning of 2010, with the difference between the contracts for delivery in October and November gaining nearly 96 cents per MMBtu. Prices peak this heating season (2009-2010) with the February 2010 contract, which settled at $5.60 per MMBtu on September 16. After this winter, prices on the 12-month futures strip are lower for delivery in the spring months. However, prices again increase significantly next summer, so that the highest priced contract in the 12-month strip is for next September at $5.97 per MMBtu.
Working natural gas in storage totaled 3,458 Bcf as of Friday, September 11, 2009, according to EIA's Weekly Natural Gas Storage Report (see Storage Figure). The implied net injection during the report week was 66 Bcf, bringing the current level of supplies in underground storage to 487 Bcf or 16.4 percent more than the 5-year (2004-2008) average for this time of year. Current stocks exceed last year's level by 496 Bcf.
The net injection during the comparable week over the past 5 years averaged 82 Bcf, while the net injection for the comparable week last year totaled 65 Bcf. The smaller injection relative to the 5-year average likely resulted in part from higher demand for natural gas in electric power sector. During the report week, the U.S. average temperature as reported by the National Weather Service was 71.1 degrees, compared with a normal average of 69.9 degrees. The number of cooling degree-days (CDDs) was 7 percent higher than normal in the United States as a whole (see Temperature Maps and Data). In particular, CDDs in the Pacific region were 34 percent higher than normal for the week. The Pacific region includes California, which has a substantial amount of natural-gas fired electric power plants.
A significant differential between current spot prices and prices for NYMEX futures contracts for next winter delivery provides a strong economic incentive for the high level of storage activity this year. On Friday, September 11, the date of the inventory measurement in this week's report, the Henry Hub average price was $2.94 per MMBtu, while the average price for delivery next winter (November through March) was $4.82 per MMBtu. Traders on the futures market are able to lock in this difference of close to $1.90 per MMBtu and cover their risk exposure by storing supplies until next winter.
Other Market Trends
EIA Releases U.S. Natural Gas Imports & Exports: 2008. EIA has released a report entitled U.S. Natural Gas Imports & Exports: 2008. The report provides an overview of U.S. international trade in 2008 as well as historical data on natural gas imports and exports. Net natural gas imports accounted for only 13 percent of U.S. consumption in 2008, compared with 16 percent of consumption in recent years. U.S. domestic natural gas production increased from 2007 to 2008, reducing the demand for imports despite an increase in domestic consumption. Although Canadian import levels decreased by 9 percent compared with 2007, Canadian pipeline imports accounted for 90 percent of total U.S. natural gas imports in 2008. Three new LNG import facilities came on line in 2008, including Sabine Pass in Louisiana, Freeport LNG in Texas, and Northeast Gateway offshore of Massachusetts, according to the report. Despite new infrastructure, however, net U.S. LNG imports fell by 58 percent in 2008, as prices climbed by more than 40 percent. While imports fell in 2008, exports of natural gas increased. According to the report, total LNG exports increased by almost 3 percent, and prices for these exports increased by about 24 percent. Pipeline exports and LNG exports increased by almost 25 percent and 7 percent from 2007 to 2008, respectively.
EIA Releases State-Level Electricity Restructuring Information. EIA recently released information detailing electricity restructuring programs, which replace a monopoly system of electric utilities with competing sellers at the State level. Of the 14 States (plus the District of Columbia) with active restructuring programs, most are located on the East Coast, north of Virginia, with the exception of Texas and some States in the Midwest. Eight States-mostly in the Western part of the country-have suspended restructuring programs. Implementing restructuring has been an ongoing process in the states with active programs. More information is available at: http://www.eia.doe.gov/cneaf/electricity/page/restructuring/restructure_elect.html. Information about natural gas residential choice programs, which allow competition among retail residential natural gas suppliers, is available at: http://www.eia.doe.gov/oil_gas/natural_gas/restructure/restructure.html. Natural Gas Transportation Update
- On Friday, September 11, Colorado Interstate Gas cancelled the force majeure at the Elk Basin compressor station on the Big Horn North Lateral in Wyoming. Capacity at the Big Horn North point was restored from 90 million cubic feet (MMcf) per day to 105 MMcf per day. The pipeline initially declared the force majeure on August 24 as a result of necessary repairs to a compressor piston.
- Gulf South Pipeline announced maintenance on September 15 at the Montpelier compressor station in Mississippi. The maintenance is scheduled to begin on September 21 and continue for approximately 6 days, and as a result capacity through the compressor station could be reduced by as much as 75,000 decatherm (Dth) per day.
- Sea Robin Pipeline has discovered a second failure on its West Leg in the Louisiana offshore while replacing a segment of the system that was damaged during last year's hurricane season. The pipeline has completed preliminary plans for repair of the second pipeline failure location. Sea Robin anticipates completing the installation of the segment replacement, dewatering, pressurizing and returning the West Leg to service by November 17, 2009. West Leg flows were approximately 50 MMcf per day prior to the hurricanes.
- Tennessee Gas Pipeline notified its customers of revised potential impacts during the fall 2009 storage shut-in tests. As a result of high storage levels, the pipeline may have to restrict a portion of firm customers' injection nominations during the tests. A number of Tennessee fields are scheduled to be shut in as part of this test, including the Bear Creek storage facility in Louisiana.