|Home > Natural Gas > Natural Gas Weekly Update|
|Weekly Natural Gas Storage|
|Major Legislative and Regulatory Actions (1935 - 2004)|
|Residential Gas Prices: Information for Consumers|
|U.S. Natural Gas Imports and Exports: Issues and Trends 2003|
|U.S. LNG Markets and Uses: June 2004|
|Natural Gas Restructuring|
|The Global Liquefied Natural Gas Market: Status and Outlook|
|Natural Gas Market Centers and Hubs|
|U.S. Natural Gas Pipeline and Underground Storage Expansions in 2003|
|Previous Issues of Natural Gas Weekly Update|
|Natural Gas Homepage|
Overview: Thursday, March 17 (next release 2:00 p.m. on March 24)
Since Wednesday, March 9, natural gas spot prices have risen at most market locations in the Lower 48 States, while declining in the Northeast region. For the week (Wednesday–Wednesday), prices at the Henry Hub increased 9 cents, or about 1 percent, to $7.08 per MMBtu. Yesterday (March 16), the price of the NYMEX futures contract for April delivery at the Henry Hub settled at $7.192 per MMBtu, increasing roughly 31 cents, or about 5 percent, since last Wednesday. Natural gas in storage was 1,379 Bcf as of March 11, which is about 24 percent above the 5-year average. The spot price for West Texas Intermediate (WTI) crude oil increased $1.76 per barrel, or about 3 percent, on the week to $56.50 per barrel or $8.741 per MMBtu.
Spot prices increased since last Wednesday, March 9, at most market locations outside the Northeast. Lingering cold temperatures and climbing crude oil prices likely contributed to the continuing strength in natural gas prices. The largest price increases, ranging between 17 and 31 cents per MMBtu, occurred in the western region of the country including California, Arizona, and the Rocky Mountains and West Texas regions. In the gas-producing states bordering the Gulf of Mexico, price hikes were relatively modest, climbing less than a dime since last Wednesday, March 9. In contrast to the rest of the Lower 48 States, prices in the Northeast region registered significant declines, as prices fell more than 40 cents per MMBtu at most locations in the region during the week. Prices at the New York citygate fell 65 cents per MMBtu or about 8 percent, and prices at the Algonquin citygate, which serves the New England region, fell 72 cents per MMBtu or about 8 percent in trading since last Wednesday, March 9. Despite price declines in the Northeast, prices in that region remain the highest in the Lower 48. Whether increasing or decreasing for the week (Wednesday-to-Wednesday), prices at most markets in the Lower 48 States remain about 25 percent higher than last year at this time. At the New York citygate, prices are $1.61 per MMBtu or 26 percent higher than last year at this time. Similarly, prices at the Henry Hub are also about 26 percent above last year’s level.
At the NYMEX, the price of the futures contract for April delivery at the Henry Hub increased about 31 cents per MMBtu since last Wednesday, March 9, to $7.192 per MMBtu. Similarly, prices for the futures contracts through the 2005 injection season (April 2005 through October 2005) also increased about 30 cents per MMBtu or about 4.5 percent. With these increases, futures prices remained in contango, as prices for the futures contracts through January 2006 were successively higher than each preceding month. Futures prices for delivery during the summer months of 2005 are extraordinarily high for this time of year. For example, the August 2005 contract settled at $7.503 per MMBtu yesterday (March 16) almost $1.63 per MMBtu or 28 percent more than the August 2004 contract at this time last year. These relatively high futures prices during the summer months apparently reflect market expectations of persisting tightness in the natural gas market, despite continued high levels of working gas in storage levels relative to the 5-year-average.
Recent Natural Gas Market Data
Working gas in storage was 1,379 Bcf, or 24.3 percent above the 5-year average, as of Friday, March 11, according to EIA’s Weekly Natural Gas Storage Report (See Storage Figure). Stock levels exceeded year-earlier levels by 275 Bcf despite an implied net withdrawal of 95 Bcf, which is large compared with the 5-year average withdrawal of 64 Bcf for this week, or last year’s withdrawal of 43 Bcf for this week. The above average withdrawal likely resulted from colder-than-normal temperatures across much of the eastern United States, especially where major population centers account for much of the space heating demand. The relatively coldest temperatures prevailed throughout regions along the Atlantic coast, where temperatures were 18 percent to 20 percent colder than normal as measured by the National Weather Service heating degree days (HDDs) for the week ending Thursday, March 10, 2005. (See HDD table). The East North Central and East South Central regions also experienced 7 percent and 16 percent colder-than-normal temperatures, respectively. Warmer-than-normal temperatures across the western regions—ranging from 14 percent to 33 percent above normal—roughly offset the cold in the East, resulting in average temperatures for the entire Lower 48 States that were only 1 percent colder than normal. If net withdrawals for the remainder of the month match the 5-year average, working gas in storage will be just below 1,300 Bcf at the end of the heating season.
Other Market Trends:
Alberta’s Potential for Conventional Natural Gas Revised Upward: The Alberta Energy and Utilities Board (EUB) and the National Energy Board (NEB) released on March 9, 2005 a report, entitled Alberta’s Ultimate Potential for Conventional Natural Gas, increasing the official estimates of resources available for development by 30 percent. The report estimates that Alberta’s ultimate potential for marketable conventional gas is 223 trillion cubic feet (Tcf) and that 101 Tcf of conventional natural gas remains to be developed. Data from 320,000 wells drilled to December 2004 were used to arrive at the estimates. Alberta is a major contributor to the North American natural gas market, as it accounts for almost 80 percent of total Canadian production, and is equivalent to about 27 percent of the total U.S. natural gas production. According to the report, recently, there have been record levels of drilling in Alberta, and Alberta appears to have reached, or at least is very near, its peak production capacity. Consequently, there is significant interest in Alberta’s ultimate potential for marketable conventional natural gas. Although increased from earlier estimates, Alberta’s remaining estimated ultimate marketable conventional natural gas will require supplements from unconventional gas supplies in order to continue meeting Canadian domestic and export demands. The United States imported almost 3.6 Tcf of natural gas from Canada, or about 82 percent of total U.S. imports in 2004.
Minerals Management Service Announces Lease Sales 194 and 197: The Minerals Management Service (MMS) of the Department of the Interior held two lease sales for tracts in the Gulf of Mexico on March 16, 2005. Final Sale 194, which encompassed areas in the Central Gulf of Mexico, received 651 bids on 428 tracts. It collected $353,961,798 in high bids from 80 companies for oil and natural gas leases in the Federal waters of the Gulf of Mexico. The lease sale area covers 4,063 blocks amounting to approximately 21.4 million acres in the Central Gulf of Mexico Outer Continental Shelf (OCS) Planning Area offshore Louisiana, Mississippi, and Alabama. The blocks are located from 3 to about 210 miles offshore in water depths of 4 to more than 3,400 meters (approximately 13 to 11,155 feet). MMS had estimated the lease sale could result in the recovery of between 276 and 654 million barrels of oil and from 1.59 to 3.30 trillion cubic feet of natural gas. Sale 197 in the Eastern Gulf of Mexico received 12 bids totaling $6,974,531 on 12 tracts offered. The Sale 197 lease area encompasses the unleased blocks in the Eastern Gulf of Mexico OCS Planning Area, directly south of Alabama. These 124 unleased blocks cover about 714,240 acres and are located from 100 to 196 miles offshore in water depths of 1,600 to more than 3,425 meters (approximately 5,249 to 11,237 feet). Estimates of undiscovered economically recoverable hydrocarbons in this sale area range from 65 to 85 million barrels of oil, and 2.65 to 3.4 billion cubic feet of natural gas.
Natural gas spot prices increased at most market locations outside of the Northeast region since last Wednesday, March 9. Prices for the futures contracts through January 2006 were successively higher than each preceding month. Working gas in storage declined to 1,379 Bcf, which is about 24 percent above the 5-year average.
Specialized Services from NEIC
|Renewables | Alternative Fuels | Prices | States | International | Country Analysis Briefs|
|Environment | Analyses | Forecasts | Processes | Sectors|