Since last Wednesday, November 11, natural gas spot prices have exhibited significant variability. Prices initially declined early in the report week at market locations across the lower 48 States. In trading on Friday, November 13, price declines ranged between $0.61 and $1.08 per MMBtu. However, prices increases since last Friday of between $1.20 and $1.71 more than offset the declines heading into the weekend. As a result of these increases, prices rose by 20 to 40 cents per MMBtu at most markets on the week. Possible factors contributing to the increase in natural gas prices include weather-related demand for natural gas, rising crude oil prices, and continued injection demand to exploit remaining arbitrage opportunities from storing gas.
Despite the recent increases, natural gas spot prices at the Henry Hub continue to trade below year-ago levels. At $3.74 per MMBtu in trading on November 18, prices at the Henry Hub were 45 percent, or $3.00 per MMBtu, below year-ago levels. Natural gas spot prices at the Henry Hub have consistently traded below year-earlier levels since October 6, 2008. Nevertheless, the recovery of the Henry Hub spot price over the past several weeks has narrowed the year-on-year differential. On September 4, 2009, prices at the Henry Hub traded at a discount of $5.40, or 75 percent, to the year-ago price. On average, prices traded yesterday about 35 percent below year-ago levels at market locations across the lower 48 States.
At the NYMEX, the prices for natural gas delivery contracts through November 2010 decreased by roughly 20 cents per MMBtu, or about 4 percent, during the report week. On the week, the price of the December contract decreased 25 cents per MMBtu, or about 6 percent. The other remaining 11 contracts on the 12-month futures strip (January 2010 through November 2010) fell between 18 and 24 cents per MMBtu, or about 3 to 5 percent. Overall, prices for the 12-month futures strip averaged $4.99 per MMBtu as of Wednesday, November 18. Prices for delivery for the 2009-2010 heating season (November 2009 through March 2010) averaged $4.62 per MMBtu.
Working gas in storage increased to 3,833 Bcf as of Friday, November 13, according to EIA's Weekly Natural Gas Storage Report. The implied net injection of 20 Bcf was 3 Bcf, or 13 percent, below last year's net injection of 23 Bcf and twice as much as the 5-year average injection of 10 Bcf for the same report week. Warmer-than-normal temperatures possibly contributed to the above-normal rate of injections during the report week. Working gas inventories are 347 Bcf higher than year-ago levels and 419 Bcf above the 5-year average level. Working gas in storage exceeds historical levels by significant margins for this time of year in each of the three storage regions.
Working gas stocks established record levels in each of the three regions, as well as on a national level. At 3,833 Bcf, working gas in storage set a new record high for natural gas inventories, exceeding the level established last week. On September 25, 2009, natural gas inventories surpassed the previous 15-year high reported on the Weekly Natural Gas Storage Report (WNGSR) of 3,545 Bcf, and the all-time high of 3,565 Bcf reported in the October 2007 Natural Gas Monthly. In addition, new record levels were established in the West and Producing regions during the week ending September 25, exceeding the previous records of 482 Bcf and 1,126 Bcf in the WNGSR, respectively. During the report week ending October 16, 2009, the East region matched its previous 15-year high level of 2,041 Bcf established on November 7, 2008, as the West and Producing regions also reached new record levels. This is the fifth consecutive week that record-highs were achieved in each region during the same report week.
Following the 9-Bcf injection during the week, working gas stocks in the Producing region climbed above the estimated peak capacity of 1,202 Bcf. Estimated peak capacity is a conservative measure of natural gas storage capacity reflecting historically demonstrated non-coincident levels of working gas in storage. According to EIA, estimated peak capacity in the Producing region was 1,202 Bcf as of April 2009 (Estimates of Peak Underground Working Gas Storage Capacity in the United States, 2009 Update). Working gas levels in the West region climbed above the demonstrated peak working gas capacity of 509 Bcf during the week ended October 23, 2009. At 2,101 Bcf on November 13, working gas levels in the East region were 77 Bcf below the demonstrated peak working gas capacity. As of November 13, working gas stocks in the lower 48 States were at nearly 99 percent of the demonstrated peak capacity of 3,889 Bcf and nearly 89 percent working gas design capacity.(see Temperature Maps and Data)
Other Market Trends
Rig Count Falls by 6 Following a 3-Week Increase. The natural gas rotary rig count fell by 6 to 728 last week, according to data Baker Hughes Incorporated released on November 13. The decline follows 3 consecutive weeks of increases and a general increase over the last several months. The current natural gas rig count is now 43 percent lower than its level of 1,267 at the beginning of 2009. However, the natural gas rig count has recovered somewhat from this year's low of 665, reached on July 17. However, the number of vertical and horizontal rigs (which includes both oil and natural gas rigs) rose over the week. The horizontal rig count rose by 5 to 512, while the vertical rig count rose by 10 to 395. While the number of horizontal and vertical rigs has fallen over the past year, the horizontal rig count has made a stronger recovery relative to vertical rigs. The current horizontal rig count is at 82 percent of its year-ago level, while vertical rigs are at 43 percent compared with year-ago levels.
Natural Gas Transportation Update
- On Saturday, November 16, Southern California Gas Company allowed an 8-day high linepack operational flow order (OFO) to expire. The OFO was originally initiated as a result of constraints on storage injection capacity.
- Northwest Pipeline Company placed a new receipt point, Meeker on the Colorado Hub connection into service on Saturday, November 16. The receipt point, which is located in Colorado and operated by Enterprise Gas Processing, has a receipt capacity of 200,000 decatherm (Dth) per day.
- Rockies Express (REX) declared a force majeure on the east leg of the pipeline on November 16, only a few days after it placed this segment into service. The force majeure was necessitated by a rupture on the pipeline east of the Chandlersville compressor station in Muskingum County, Ohio. The affected section of the pipeline was immediately isolated; however, REX has not yet determined the length of the outage. As a result of the rupture, nominations through Segment 390 in Ohio are not being scheduled and five pipeline interconnects remain unavailable.
- Kern River Gas Transmission Company filed a formal application with the Federal Energy Regulatory Commission last week to expand its pipeline between Lincoln County, Wyoming, and Clark County, Nevada, by 266,000 Dth per day. The proposed expansion will include 28 miles of 36-inch diameter looping, a new compressor station in Beaver County, Utah, and additional compression along the line in Wyoming and Nevada. The pipeline's firm transportation agreements with Nevada Power are primarily driving the expansion, which will help Nevada Power serve its increasing retail electricity load. The proposed expansion could be placed into service on November 1, 2011.
- Northern Border Pipeline Company issued an update on November 17, citing points that will be out of service during the pipe relocation. The pipeline initially announced on November 2 that it was planning to replace a section of the 36-inch pipeline near Elwood, Illinois next month. This project, tied to the development of the Joliet CenterPoint Intermodal facility in Illinois, has a planned start date of Saturday, December 5 and the pipeline expects that all work should be completed prior to the start of gas day December 7. During the pipeline segment replacement work, Northern Border valves 76 and 77 will be closed, fully isolating a number of delivery points, including the Jackson Creek, Joliet, Noel, Elwood, Manhattan, and other delivery points in Will County, Illinois. Furthermore, the pipeline will not be able to physically receive any gas from ANR Pipeline at the Des Plaines interconnect during the outage.