Overview:  Thursday, November 9 (next release 2:00 p.m. on November 16, 2006)

Natural gas spot price movements were mixed since Wednesday, November 1, including significant price decreases at locations in the Rockies, relatively small increases along the Gulf Coast, and varied movements in other regions.  The spot price at the Henry Hub increased 21 cents per MMBtu, or about 3 percent, to $7.37 per MMBtu.  The NYMEX futures contract for December delivery at the Henry Hub gained about 11 cents since last Wednesday to close yesterday (November 8) at $7.823 per MMBtu.  Natural gas in storage as of Friday, November 3, was 3,445 Bcf, which is 7.7 percent above the 5-year average.  The spot price for West Texas Intermediate (WTI) crude oil increased $1.29 per barrel, or 2.2 percent, since last Wednesday to trade yesterday at $59.93 per barrel or $10.33 per MMBtu. Yesterday’s crude oil price was only 23 cents higher than the year-ago level, when crude oil traded at $59.70 per barrel on November 8, 2005.

 

 

Prices:

Overall, natural gas spot price movements in the Lower 48 States varied during the report week. Mild temperatures across the country this week (Wednesday-Wednesday) likely reduced heating demand in many key market areas; however, there was some cooling demand in southern California that resulted from the 90-degree weather that prevailed early this week. Prices at market locations in and to the west of the Rocky Mountains generally decreased on the week, with declines ranging between 3 cents and $2.69 per MMBtu. Average spot prices in the Rockies were $5.09 per MMBtu on Wednesday, November 8, with six locations recording prices below $4 per MMBtu. The largest decrease of $2.69 per MMBtu on the week occurred at the Questar trading location, where yesterday gas traded at $3.20 per MMBtu, the lowest spot price in the Lower 48 States.  Despite the comparatively low price at Questar, the spot price at this trading location recovered since Monday, November 6, when the spot price hit a low of $1.67 per MMBtu. This was the lowest spot price of any location since September 15, 2006, when Northwest Pipeline’s trading location south of Green River recorded a $1.63 per MMBtu spot price. These decreases were not matched elsewhere in the Lower 48 States.  Locations along the Gulf of Mexico mostly recorded increases on the week. The Henry Hub spot price increased 21 cents or about 3 percent on the week to $7.37 per MMBtu. Similarly, other market locations in Louisiana increased between 6 and 34 cents on the week to a regional average price of $7.35 per MMBtu. Average prices in the key Northeast and Midwest consuming areas as of yesterday were $7.90 and $7.57 per MMBtu, respectively.

 

 

 

The price of the NYMEX futures contract for December delivery gained about 11 cents, or 1.4 percent, since last Wednesday to settle at $7.823 per MMBtu yesterday.  The price of the December contract increased in four out of the five trading sessions this week, and the 39-cent decrease during Monday’s trading session was not large enough to offset the previous and subsequent increases. The prices for other futures contracts for the current heating season changed relatively little with increases of about 0.7 percent, 0.9 percent, and 1.1 percent, respectively, for the January 2007, February 2007, and March 2007 contracts. Prices for the futures contracts for delivery during the 2007 injection season also increased, albeit slightly more than the heating season contracts, with increases around 14 cents or 1.8 percent. The February 2007 futures contract traded as the highest-priced contract as of yesterday (November 8), settling at $8.332 per MMBtu. The heating season futures contracts continue to trade at a premium to the Henry Hub spot price, with the premium averaging 79 cents. The 12-month strip, which is the average of the futures prices for the coming year, increased about 12 cents or 1.5 percent per MMBtu this week to $8.067 per MMBtu.

 

The 2006 injection season:  The past injection season (April 1-October 31) was marked by several different near-record-setting events. The average spot price at the Henry Hub of $6.25 per MMBtu during the past refill season was $2.53 per MMBtu, or 29 percent, below the level of the 2005 injection season. Factors contributing to this year’s comparatively lower prices include production recovery in the Gulf of Mexico following last year’s Hurricanes Rita and Katrina, lack of any significant hurricane activity or other supply disruption, and large volumes of natural gas in underground storage. Despite these favorable market conditions, the average Henry Hub spot price was second only to last year’s level. This was undoubtedly due to slightly lower natural gas production, increasing demand, and lower LNG imports. Even before the onset of the injection season, the Henry Hub spot price had been decreasing, hitting $5.18 per MMBtu in early July. However, owing to temperatures that were much above normal during July and the ensuing high natural gas demand for electric power generation, spot prices rose to $8.67 per MMBtu on August 1. The Henry Hub spot price generally declined thereafter until September 29, when it reached $3.66 per MMBtu.  Prices increased by $2.99 per MMBtu since then, ending the refill season on October 31 at $6.65 per MMBtu. 

 

Weather during the 2006 injection season was warmer-than-normal and generally warmer than last year for the same 7-month period as measured by population-weighted cooling degree-days (CDDs) published by the National Weather Service. Six of the seven months were warmer than normal. Temperatures in July and August 2006 were among the warmest on record, resulting in record high electric power demand, which led to two natural gas net withdrawals during these 2 months (for a more detailed discussion, see Withdrawals from Working Natural Gas Stocks During Summer 2006). September 2006, with about 7 percent fewer CDDs than normal, was the only month during the injection season with lower-than-normal temperatures.  Overall, temperatures during the injection season were about 18 percent higher than normal.

 

The 2006 injection season ended with approximately 3,448 Bcf of working gas as of October 31, which is the second-highest volume of natural gas in storage recorded for this date. Natural gas inventories were above historical averages through much of the refill season owing greatly to the large volume remaining in storage at the end of the 2005-2006 heating season.  Working gas in storage at the end of March 2006 was 1,692 Bcf, which exceeded the previous record by 174 Bcf.  This volume also was 654 Bcf or nearly 63 percent above the 5-year-average natural gas volume.  Although a relatively high volume of gas was in storage as of the end of October, net injections during the 2006 injection season were relatively low compared with the 5-year average. Net injections between April 1 and October 31 amounted to 1,756 Bcf, which was 83 percent of the 5-year average net injections. The difference between actual net injections and the 5-year average is the equivalent of 1.66 Bcf per day for the entire refill season.

 

Recent Natural Gas Market Data

 

Estimated Average Wellhead Prices
	May-06	June-06	July-06	Aug-06	Sep-06	Oct-06
Price ($ per Mcf)	6.19	5.80	5.82	6.51	5.51	5.03
Price ($ per MMBtu)	6.03	5.65	5.67	6.34	5.37	4.90
Note: Prices were converted from $ per Mcf to $ per MMBtu using an average heat content of 1,027 Btu per cubic foot as published in Table A4 of the Annual Energy Review 2002.
Source:  Energy Information Administration, Office of Oil and Gas.

 

Storage:

Working gas in underground storage decreased to 3,445 Bcf as of Friday, November 3, according to EIA’s Weekly Natural Gas Storage Report (See Storage Figure). The implied net withdrawal of 7 Bcf for the week sharply contrasts with both the 5-year average net injection of 23 Bcf and last year’s net injection of 56 Bcf for the same week. During the week ending November 2, 2006, the weather for the country as a whole was 7 percent colder than normal and 8 percent colder than last year, as measured by degree-day data reported by the National Weather Service. In the East North Central Census Division, which includes Chicago and other Midwest population centers with significant space heating demand, temperatures were more than 18 percent colder than normal and about 20 percent colder than last year. Similarly, temperatures in the West North Central were 18 percent colder than normal and 47 percent colder than last year for the same week. On the other hand, the New England and Middle Atlantic Census Divisions experienced temperatures that were 5 and 6 percent warmer than normal (See Temperature Maps).  There was a 10-Bcf withdrawal from the storage facilities in the East region. The West and the Producing regions both recorded net injections for the week. An estimated 3,448 Bcf of natural gas was in storage at the end of the 2006 injection season (April 1-October 31).  This is the second-highest volume on record for the end of October.  The peak volume occurred in 1990, when the heating season started with 3,467 Bcf of natural gas in underground storage. Estimated inventories as of the end of the injection season were 390 Bcf, or 12.8 percent, above the previous 5-year (2001-2005) average of 3,058 Bcf, and 251 Bcf, or about 8 percent, higher than last year’s level of 3,194 Bcf.

 

 

 

Other Market Trends:

EIA Releases Its November Short-Term Energy Outlook: According to the Energy Information Administration’s (EIA) latest Short Term Energy Outlook (STEO), released on November 7, 2006, natural gas spot prices at the Henry Hub are expected to average about $7.06 per thousand cubic feet (Mcf) in 2006 and then increase to $7.79 per Mcf in 2007.  Owing to higher levels of natural gas in storage compared with the 5-year average and forecasts of warmer-than-normal weather, the average monthly Henry Hub spot price is expected to remain below $9 per Mcf throughout this heating season, although daily prices may exceed that level at times.  Natural gas spot prices fell in September because of moderate temperatures and high inventories in underground storage.  Since then prices have risen, as cooler temperatures resulted in the onset of heating demand.  Total U.S. natural gas consumption in 2006 is expected to remain largely unchanged from the 2005 levels, but then increase by 1.3 percent in 2007. This winter is expected to be colder than last winter, which will result in higher residential and commercial demand for the season.  Similarly, the 2007 summer is projected to be cooler than normal; however, this would result in lower natural gas demand for electricity generation.  As of October 27, the level of working gas in storage was 3,452 Bcf, which was 288 Bcf above the levels last year during the same time and 276 Bcf more than the 5-year average.  Domestic dry natural gas production in 2006 is expected to increase by 1.3 percent in 2006 and 0.4 percent in 2007. 

 

Natural Gas Transportation Update:

• On Saturday, November 4, and again on Thursday, November 9, Pacific Gas & Electric Company (PG&E) declared an operational flow order (OFO).  PG&E placed a stage 2 high-inventory OFO in effect, assessing charges of $1 per decatherm (Dth) for exceeding a 5-percent tolerance on positive daily imbalances.
• On November 7, Northwest Pipeline Corporation issued an OFO warning to all shippers.  The pipeline further noted that as long as the Jackson Prairie storage balance exceeds 1.2 million Dth, Northwest will use its storage flexibility to offset any existing OFOs.  Storage at the Jackson Prairie facility has been reduced below Northwest’s threshold for offsetting OFO’s, mostly because of customer drafting and over-scheduling at the Kemmerer compressor station.  Northwest requested that customers realign supplies from domestic supply points to Canadian supply points in order to create some operational flexibility entering the upcoming winter.  If nominations through Kemmerer continue to exceed capacity, Northwest will be required to take action.  Further, on November 8, Northwest cut all alternate capacity through its Roosevelt compressor station in an attempt to reduce linepack at its Kemmerer compressor station.  Northwest will begin scheduling alternate capacity as soon as operational conditions permit. Furthermore, alternate gas will be reduced in order to remediate the over-scheduling at the Kemmerer station.
• On November 8, 2006, ANR Pipeline Company announced a capacity reduction owing to emergent engine repairs at the St. John and Bridgman compressor stations, located along the Michigan Leg South in the Northern Fuel Segment.  ANR is currently working on the repairs at both compressor stations and will reduce the total capacity by 150 MMcf/d at the St. John station from west to east, leaving 1,155 MMcf/d available.  During the period November 8 through 10, based on current nominations along the Michigan leg, it is likely that the reductions will result in the curtailment of firm secondary and interruptible transportation nominations.  

 

 Short-Term Energy Outlook