Natural Gas

Overview: Thursday, February 8, 2007 (next release 2:00 p.m. on February 15, 2007)

Since Wednesday, January 31, natural gas spot price movements were mixed with prices generally increasing east of the Mississippi River and decreasing to the west of it. On Wednesday, February 7, prices at the Henry Hub averaged $7.89 per MMBtu, a gain of 14 cents per MMBtu, or about 2 percent, from the level the previous Wednesday. The NYMEX futures contract for March delivery at the Henry Hub settled at $7.709 per MMBtu on Wednesday, February 7, rising about 4 cents per MMBtu, or nearly 1 percent, from the settlement price of $7.667 recorded last Wednesday, January 31.Natural gas in storage was 2,347 Bcf as of February 2, which is 19 percent above the 5-year average. The spot price for West Texas Intermediate (WTI) crude oil decreased 42 cents per barrel, or about 1 percent, on the week (Wednesday-Wednesday) to $57.75 per barrel or $9.96 per MMBtu.

 Prices:

Spot price movements differed among the various markets since last Wednesday, January 31, with prices generally increasing east of the Mississippi River and decreasing elsewhere. A cold front moving in from Canada contributed to the price increases as extremely cold temperatures increased heating demand for natural gas. Prices in the affected areas increased heading into the weekend as extreme weather conditions strained system capacity, leading some natural gas transportation providers such as Columbia Gas Transmission Corporation and Dominion in the Northeast region to announce that pipeline capacity would not be available for non-firm deliveries of natural gas (see Natural Gas Transportation Update below). In trading on Monday, February 5, prices peaked at most market locations in the Midwest, Northeast, and Louisiana regions with the largest increases occurring principally in the Northeast region, but declined in each successive day of trading since then. Overall, prices rose about 12 cents per MMBtu on average in the Louisiana and Midwest regions, and climbed about 95 cents per MMBtu on average in the Northeast region since Wednesday, January 1. Despite these relatively modest price increases, prices in the Northeast region were characterized by considerable volatility during the week as prices at 7 of the 12 market locations in the region climbed past the $16 mark on Tuesday before falling back to $11.36 or less in trading on Wednesday, February 7. The highest prices in the Northeast region occurred at the New York citygate and at the Iroquois (zone 2) market location, serving parts of Suffolk County in New York, and Connecticut, where prices peaked at $40.03 and $17.87 per MMBtu, respectively, on Monday, February 5. At $40.03 per MMBtu, the price was the second-highest daily average ever reported at the New York citygate, falling below only the $44.81 per MMBtu posted on January 16, 2004. West of the Mississippi, where temperatures were not as frigid, prices generally declined. The largest declines occurred in the Rocky Mountains region, where prices fell about 58 cents per MMBtu on average. In Arizona, Nevada, and California, price declines ranged between 7 and 16 cents per MMBtu on average, while prices in Texas fell between 24 and 34 cents per MMBtu on average. Prices remain below levels reported last year at this time, with prices at the Henry Hub 37 cents per MMBtu or 4 percent below last year's level.

  At the NYMEX, prices for the futures contracts for the next 12 months increased across the board with the 12-month futures strip (March 2007 through February 2008) climbing about 9 cents per MMBtu, or about 1 percent, since last Wednesday, January 31, in a relatively quiet week of trading characterized by daily price changes of less than a dime on average. While the NYMEX futures contract for March delivery at the Henry Hub settled at $7.709 per MMBtu on Wednesday, February 7, rising about 4 cents per MMBtu, or less than 1 percent, prices for delivery in the ensuing months increased by slightly larger margins, climbing a little over 1 percent. Overall, the 12-month futures strip (March 2007 through February 2008) traded at a premium of about 43 cents per MMBtu relative to the Henry Hub spot price, averaging $8.32 per MMBtu as of Wednesday, February 7.

 Recent Natural Gas Market Data

 Storage:

Working gas in storage totaled 2,347 Bcf as of Friday, February 2, which is about 19 percent above the 5-year average inventory level for the report week, according to EIA's Weekly Natural Gas Storage Report (See Storage Figure). As of February 2, stocks exceeded the 5-year average by 378 Bcf, but fell below last year's level by 26 Bcf.On the week, withdrawals from storage totaled 224 Bcf compared with the 5-year average withdrawal of 148 Bcf and last year's net withdrawal of 46 Bcf for the same report week. Colder-than-normal temperatures prevailed during the report week, likely contributing to the larger than normal withdrawals from working gas. After increasing steadily for the past 4 weeks, heating degree-days in the Lower 48 States were about 13 percent above normal levels during the report week. Heating degree-days were between 9 and 27 percent above normal levels in each of the nine Census Divisions. Furthermore, heating degree-days exceeded last year's levels by significant margins in each of the Census Divisions, with heating degree-days for the Lower 48 States about 54 percent above last year's level (See Temperature Maps).

 Other Market Trends:

EIA Releases Summary of Natural Gas International Trade in 2005: Natural gas flows into and out of the United States in 2005 reflected the increasingly integrated North American marketplace and this country's evolving participation in global liquefied natural gas (LNG) trade. The volume of net natural gas imports for the year increased 6.1 percent from 2004 to 2005, according to a new Energy Information Administration report, U.S. Natural Gas Imports and Exports: Issues and Trends 2005. Net imports moved up to 3,612 billion cubic feet (Bcf), an increase of 208 Bcf. This increase was primarily due to an incremental rise in U.S. imports of natural gas from Canada and a decrease in U.S. exports to both Mexico and Canada. Record-high domestic prices following 2005's devastating hurricane season, which resulted in massive volumes of natural gas production being shut in by producers in the Gulf of Mexico region, translated into higher prices in U.S. international trade as well. The price of natural gas imports moved up sharply in 2005 to an annual average of $7.92 per MMBtu. For the first time since 2002 and only the second time in the past decade, U.S. LNG imports decreased. The average annual price of imported LNG on the basis of heat content ($7.82 per MMBtu) was lower than the price of natural gas imports delivered by pipeline, demonstrating the competitiveness of LNG for import to the U.S. market. However, constraints in global supplies and price competition, particularly from France and Spain in the Atlantic Basin portion of the global market, limited shipments to the United States. LNG imports for the year totaled 631 Bcf, down 3.2 percent from the level in 2004. In total, the United States received natural gas from nine countries and exported natural gas to three countries. Net imports accounted for 16.2 percent of overall consumption in 2005.

 LNG Imports Decline Again in 2006: Imports of liquefied natural gas (LNG) to the continental United States declined in 2006, as competition from other countries diverted LNG volumes away from the U.S. market. According to the Department of Energy's Office of Fossil Energy, the United States imported from four countries the gaseous equivalent of 584 Bcf of LNG, which was a decrease of 8 percent from the 631 Bcf imported in 2005 (see Figure, "U.S. LNG Imports by Month and Source Country, 2006"). Deliveries from Trinidad and Tobago declined by about 11 percent to 389 Bcf, but the country was once again by far the leading supplier of LNG to the United States, accounting for 67 percent of total LNG deliveries. In its first full-year of exporting LNG, Egypt became the second largest supplier to the United States in 2006 with volumes of 120 Bcf. The United States received supplies from Nigeria totaling 57 Bcf, a considerable increase from just 8 Bcf received in the prior year as new LNG production capacity came on-line in that country. Algeria, formerly the sole supplier of LNG to the United States, exported 17.4 Bcf to the United States, down nearly 80 Bcf from 2005, with no shipments in the last 5 months of 2006. The mix of source countries for the year was considerably different than in 2005, when the United States also received LNG imports from Malaysia, Qatar, and Oman.

  EIA Releases Its Latest Short-Term Energy Outlook: The Energy Information Administration (EIA) on February 6, 2007, released its latest Short Term Energy Outlook (STEO), which includes forecasts through December 2008. The February STEO highlights the effects of warmer-than-normal temperatures through mid-January, which resulted in reduced demand for heating fuels across much of the United States, lowering expected prices of petroleum products and natural gas. The projected West Texas Intermediate crude oil price was lower compared with last month's STEO, which now is projected to average about $59.50 per barrel in 2007 and $62.50 per barrel in 2008. Projections of U.S. heating expenditures for the 2006-2007 winter have declined in the past two outlooks, because of a relatively warm winter through the month of January.U.S. natural gas heating expenditures for the 2006-2007 winter are projected to be $790 per household, which is $150 less than last winter. Assuming normal weather after January 2007, the average for the Henry Hub spot price will remain below $7.10 per Mcf in 2007 and $7.60 in 2008. Total U.S. natural gas consumption in 2007 is expected to increase by 2.7 percent. Domestic dry natural gas production increased by 2.2 percent in 2006.It is projected to increase by 2.7 percent in 2007 and 0.7 percent in 2008, respectively. As of January 26, the level of working gas in storage was 2,571 billion cubic feet (Bcf), which was 152 Bcf above the levels last year at the same time and 454 Bcf higher than the 5-year average. Assuming normal weather through March 31, working gas in storage is expected to fall to 1,720 Bcf, the highest level at the end of the heating season since 1991.

 Natural Gas Transportation Update:

• As of Saturday, February 3, Dominion had no interruptible or secondary capacity available at six New York utility delivery points, adding two additional delivery points on February 5. The cold weather, both in its duration and magnitude, as well as the firm load requirements forced the pipeline to limit service. Additionally, in anticipation of discrepancies between quantities delivered to and received on behalf of their customers, Dominion also issued an OFO for the eight New York area delivery points. Dominion also declared an OFO on its PL-1 system for deliveries to Virginia and Maryland because of the high heating load over the past week.
• Columbia Gas Transmission Corporation declared February 3-6 critical days for natural gas shippers in its eastern U.S. market areas owing to the cold weather that engulfed the region. Based on forecasts, available facilities and capacity utilization, all available capacity was needed to meet firm service obligations. While no non-firm capacity was available on the Columbia Gas system during this time, shippers with firm service or secondary priority rights were not affected. Columbia Gas Transmission transports an average of about 3 Bcf per day of natural gas though a 12, 750-mile pipeline network to communities in 10 States.
• Northern Natural Gas declared a system overrun limitation for gas days February 7-9, as a result of the below-freezing temperatures. The limitation is in effect for all of the pipeline's market area zones.
• Mississippi River Transmission posted a system protection warning (SPW) for Friday, February 2, also as a result of the cold weather. Failure to comply at any time within the SPW period would result in shippers being issued an individual operational flow order (OFO).
• Southern Natural Gas Company implemented a type 6 OFO for short imbalances on Friday, February 2, which lasted until Tuesday, February 6. However, because of continued critical conditions on its system the pipeline reinstated the type 6 OFO for gas day Friday, February 9, until further notice. Negative balances exceeding 8 percent carry a $15.00 per decatherm (Dth) penalty, while 5 to 8 percent imbalances and 2 to 5 percent daily imbalances carry $5.00 and $1.00 per Dth, respectively. Imbalances of up to 2 percent or 200 Dth will not penalized.
• On February 2, ANR Pipeline Company declared an extreme condition as projected temperatures across much of Wisconsin were expected to be at or around zero degrees. The extreme condition declaration lowered the imbalance tolerance from 10 percent to 5 percent, and did not allow for any unauthorized overruns under several firm and interruptible rate schedules.
• Spectra Energy Corporation's Moss Bluff storage facility announced that because of the anticipated high withdrawals it would not accept excess withdrawals or interruptible delivery nominations to one meter on its system. The facility, located in Liberty County, Texas, has a working capacity of 16 Bcf.

Short-Term Energy Outlook