Outlook and Recommendation
The U.S. Energy Information Administration estimates that U.S. natural gas pipeline companies added about 2,400 miles of new pipe to the grid as part of over 25 projects in 2011. New pipeline projects entered service in parts of the U.S. natural gas grid that can be congested: California, Florida, and parts of the Northeast Only a portion of this capacity serves incremental natural gas use; most of these projects facilitate better linkages across the existing natural gas grid.
By convention, the industry expresses annual capacity additions as the sum of the capacities of all the projects completed in that year. By this measure, the industry added 13.7 billion cubic feet per day (Bcf/d) of new capacity to the grid in 2011. The six largest projects put into service in 2011 added 1,553 miles and about 8.2 Bcf/d of new capacity to the system. Much of this new capacity is for transporting natural gas between states rather than within states. Golden Pass, Ruby Pipeline, FGT Phase VIII, Pascagoula Expansion, and Bison Pipeline projects added 6.1 Bcf/d, or about 80%, of new state-to-state capacity.
Natural gas pipeline capacity additions in 2011 were well above the 10 Bcf/d levels typical from 2001-2006, roughly the same as additions in 2007 and 2010, but significantly below additions in 2008 and 2009 (see chart below). Capacity added in 2008 and 2009 reflected a mix of intrastate and interstate natural gas pipeline expansions, related mostly to shale production, liquefied natural gas (LNG) terminals, and storage facilities.
This over production, without new uses or demands has increased inventories and pushed Natural Gas prices below estimates and projections. Natural Gas hit a bottom in February of 2.32 but moved back up to 2.80 on unimportant news and predictions of cold weather, and then begin to fall back down to find a bottom. NG as is trading around 2.47 at present and will most likely fall to the 2.42 number in March and then drop again when winter is officially over.
Natural Gas Inventory (EIA)
Summary from the EIA report
Average daily power prices in the Northeast and Midwest from the beginning of November 2011 through the first week of February have been unusually low. The driving factor is warm weather. Warm winter weather decreases the demand for electricity, which puts downward pressure on prices. The warm weather also cuts demand for natural gas, both as a heating fuel and as a fuel for power generation. This acts to hold down natural gas spot prices, which in turn decreases the cost of generating power.
Northeastern and Midwestern wholesale power prices typically are linked closely to natural gas prices, since natural gas-fired generators are often the marginal provider of power, and the marginal generator sets the power price in those markets. This connection is illustrated by the close tracking of the natural gas price (red line) and power price (blue line) in the chart above. This winter, warm weather and robust natural gas supplies moderated natural gas prices.
Cold weather around January 4 and January 16 contributed to higher spot natural gas and power prices in hubs in New York and New England. While the average January temperature at the LaGuardia Airport in New York City was 37°F, on January 4, the average daily temperature dipped to 19°F, and the average daily temperature was under 25°F on January 15 and 16.
During colder weather, demand for natural gas as a heating fuel increases, raising the spot market prices for natural gas, and therefore, for power as well. Northeastern price spikes are typically caused by natural gas pipeline capacity constraints on the natural gas grid serving this region and may not show up in other regions (see prices at Mid-Atlantic and Midwestern hubs below).
- The return of warmer-than normal temperatures was likely the catalyst that caused natural gas prices to resume their multi-week downtrend. The Henry Hub price closed at $2.44 per million British thermal units (MMBtu) on February 29, down 16 cents for the week.
- At the New York Mercantile Exchange (NYMEX), the April 2012 natural gas contract fell 15.9 cents per MMBtu for the week to close at $2.616 per MMBtu.
- Working natural gas in storage eased slightly last week to 2,513 billion cubic feet (Bcf) as of Friday, February 24, according to the U.S. Energy Information Administration's (EIA) Weekly Natural Gas Storage Report (WNGSR). The implied net withdrawal for the week was 82 Bcf, positioning storage volumes 756 Bcf above year-ago levels.
- The natural gas rotary rig count, as reported February 24 by Baker Hughes Incorporated, decreased by 6 to 710 active units. Meanwhile, oil-directed rigs dropped by 7 to 1,265 units.
March Major Economic Events
- This Week in PetroleumRelease Schedule: Wednesday @ 1:00 p.m. EST (schedule)
- Gasoline and Diesel Fuel UpdateRelease Schedule: Monday between 4:00 and 5:00 p.m. EST (schedule)
- Weekly Petroleum Status ReportRelease Schedule: The wpsrsummary.pdf, overview.pdf, and Tables 1-14 in CSV and XLS formats, are released to the Web site after 10:30 a.m. (Eastern Time) on Wednesday. All other PDF and HTML files are released to the Web site after 1:00 p.m. (Eastern Time) on Wednesday. Appendix D is produced during the winter heating season, which extends from October through March of each year. For some weeks which include holidays, releases are delayed by one day. (schedule)
- Heating Oil & Propane Update (October-March) Heating Oil, Propane Residential and Wholesale Price DataRelease Schedule: Wednesday at 1:00 p.m. EST
- Weekly Coal ProductionRelease Schedule: Thursday by 5:00 p.m. EST
- Weekly NYMEX Coal FuturesRelease Schedule: Monday by 5:00 p.m. EST
- Coal News & MarketsRelease Schedule: Monday by 5:00 p.m. EST
- Natural Gas Weekly UpdateRelease Schedule: Thursday between 2:00 and 2:30 p.m. (Eastern Time)
- Weekly Natural Gas Storage ReportRelease Schedule: Thursday at 10:30 (Eastern Time) (schedule)
Natural Gas Pivot Points (Time Frame: 1 Day)
Name S3 S2 S1 Pivot R1 R2 R3