Regional average natural gas spot prices increased between 5 and 16 cents per MMBtu week-on-week, with the notable exception of pricing points located in the Northeast, which increased over $20.00 per MMBtu for the report week. The natural gas price basis (the difference between a regional price and the U.S. benchmark Henry Hub price) at trading points for New York and New England at the close of trading on Wednesday, January 23 reached their highest levels in over nine years.
The Nymex February futures price rose from $ 3.435 per MMBtu last Wednesday to $3.554 per MMBtu yesterday. During the week, the futures price spread over the Henry Hub daily spot price averaged between -7.2 cents and 5.4 cents per MMBtu. The 12-Month Strip (average of February 2013 to January 2014 contracts) gained 12 cents per MMBtu, starting at $3.654 per MMBtu last Wednesday and landing at $3.774 per MMBtu yesterday.
Consumption particularly rose in the Northeast. On January 22, natural gas consumption in the Northeast increased to 33.6 billion cubic feet per day (Bcf/d), 56 percent above the previous week’s (January 14-January 20) seven-day average of 21.6 Bcf/d, according to data from Bentek. On January 23, Bentek reported that Northeast consumption rose to 36.2 Bcf/d, or 68 percent above the seven-day average. For both of these days, consumption in New York City rose to over 4.1 Bcf/d, or 41 percent above the 30-day average of 2.9 Bcf/d. Consumption in New England was just under 5.0 Bcf/d on January 22, and just under 5.1 Bcf/d on January 23, almost 22 percent above its 30-day average of 4.2 Bcf/d.
The increase in U.S. residential/commercial consumption, coupled with the slight increase for industrial consumption that Bentek estimated for the week, far exceeded the 2.5 percent drop in power sector consumption below last week’s daily average. Power burn fell most significantly in the Southwest and Texas.
Bentek estimates that the average daily natural gas supply for this report week increased modestly by 1.9 percent over the previous week’s daily average. This resulted from around 27 percent and 17 percent increases in imports from Canada and as LNG, respectively. Imports from Canadian and LNG imports are 8.5 percent higher and 48 percent lower than last year’s levels during the same period, respectively. Dry natural gas production stayed unchanged from the previous week.
Working natural gas in storage decreased to 2,996 Bcf as of Friday, January 18, according to EIA's WNGSR. This represents an implied net withdrawal of 172 Bcf from the previous week. This week's net withdrawal was 4 Bcf smaller than the 5-year average net withdrawal of 176 Bcf, and 10 Bcf larger than last year's average net withdrawal of 162 Bcf. Inventories are currently 157 Bcf (5.0 percent) less than last year at this time and 320 Bcf (12.0 percent) greater than the 5-year average.
All three storage regions posted declines this week. Inventories in the East, West, and Producing regions decreased by 80 Bcf (the 5-year average net withdrawal is 106 Bcf), 39 Bcf (the 5-year average net withdrawal is 18 Bcf), and 53 Bcf (the 5-year average net withdrawal is 51 Bcf), respectively.
In the Producing region, working natural gas inventories decreased 15 Bcf (5.4 percent) in salt cavern facilities and decreased 37 Bcf (4.4 percent) in nonsalt cavern facilities.