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

Since Wednesday, October 25, natural gas spot prices decreased at most market locations in the Lower 48 States.  On Wednesday, November 1, prices at the Henry Hub averaged $7.16 per MMBtu, a decline of 4 cents per MMBtu, or less than 1 percent, since the previous Wednesday.  The NYMEX futures contract for December delivery at the Henry Hub settled at $7.712 per MMBtu, on Wednesday, November 1, falling about 62 cents per MMBtu, or 7 percent, from the settlement price of $8.328 recorded last Wednesday, October 25.  Natural gas in storage was 3,452 Bcf as of October 27, which is about 9 percent above the 5-year average.  The spot price for West Texas Intermediate (WTI) crude oil decreased 45 cents per barrel, or less than 1 percent, on the week (Wednesday-Wednesday) to $58.64 per barrel or $10.11 per MMBtu.

 

 

Prices:

Spot prices decreased at most market locations since last Wednesday, October 25, with decreases of up to 22 cents per MMBtu, although some markets posted price hikes.  While the week-on-week price changes were relatively modest, intraweek trading was characterized by considerable variability.  Prices posted significant gains in trading at most market locations on Thursday, October 26, as cold temperatures contributed to increased heating demand for natural gas.  These gains were followed by warmer temperatures and 3 successive days of declining prices, reversing Thursday’s gains.  On Wednesday, November 1, prices again rallied, climbing between 25 and 84 cents per MMBtu as a cold front moved into the Midwest.  For the week, most regions in the Lower 48 States posted region-wide average declines of up to 12 cents per MMBtu with the exception of the California, Northeast, and Florida regions.  Price hikes at northern California market locations led to an average increase of about 1 cent per MMBtu in the State.  In the Northeast region, price increases at the New York citygate and on the Algonquin Pipeline contributed to an average increase of about 2 cents per MMBtu in the region.  With an increase of 34 cents per MMBtu, or about 5 percent, the Florida citygate posted the largest increase in the Lower 48 States since last Wednesday, October 25.  Prices remain below the level reported last year at this time, with prices at the Henry Hub $3.63 per MMBtu or nearly 34 percent below last year’s level.

 

 

 

At the NYMEX, prices for the futures contracts for the next 12 months decreased across the board with the 12-month futures strip (December 2006 through November 2007) falling about 35 cents per MMBtu, or about 4 percent, since last Wednesday, October 25. The largest decreases on the 12-month futures strip occurred for contracts for delivery during the remaining heating-season months (December 2006 through March 2007), as prices decreased by about 6 percent on average since last Wednesday, October 25.  Averaging $8.08 per MMBtu, the futures contract prices for delivery during the upcoming heating season traded at an average premium of about $0.92 per MMBtu to the Henry Hub spot price.  Overall, the 12-month futures strip (December 2006 through November 2007) traded at a premium of $0.79 per MMBtu relative to the Henry Hub spot price, averaging $7.95 per MMBtu as of Wednesday, November 1.  The futures contract for October delivery at the Henry Hub expired at $7.153 per MMBtu on Friday, October 27, declining $1.761 per MMBtu, or nearly 33 percent, during its tenure as the near-month contract. 

 

Recent Natural Gas Market Data

 

Estimated Average Wellhead Prices
	Apr-06	May-06	June-06	July-06	Aug-06	Sep-06
Price ($ per Mcf)	6.59	6.19	5.80	5.82	6.51	5.51
Price ($ per MMBtu)	6.42	6.03	5.65	5.67	6.34	5.37
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 storage totaled 3,452 Bcf as of Friday, October 27, which is about 9 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 October 27, stocks exceeded last year’s level by 288 Bcf and the 5-year average by 276 Bcf. For the week, the implied net withdrawal of 9 Bcf contrasts with the 5-year average of injection 30 Bcf and last year’s injection of 36 Bcf. This is the earliest weekly withdrawal approaching the heating season since 1994 when the weekly data series began. The only other instance of a withdrawal in October was reported for the week ending October 31, 1997. Unusually colder-than-normal temperatures that prevailed during the report week in large sections of the country likely contributed to the withdrawal from working gas stocks as the unseasonably cool temperatures would have increased heating demand for natural gas.  During the report week, heating degree-days in the Lower 48 States exceeded normal levels by about 31 percent.  Heating degree-days along the northern tier of the Lower 48 States, including the Northeast, Middle Atlantic, East North Central, West North Central, and Mountain regions, exceeded normal levels by 9 to 54 percent.  (See Temperature Maps)

 

 

 

Other Market Trends:

FERC Issues Notice of Proposed Rulemaking: The Federal Energy Regulatory Commission (FERC) issued a notice of proposed rulemaking on October 25, 2006, that seeks to improve coordination between the natural gas and electric industries by revising the agency’s regulations governing the standards for business practices and electronic communications between the two sectors. The FERC proposal incorporates certain standards promulgated by the Wholesale Gas Quadrant and the Wholesale Electric Quadrant of the North American Energy Standards Board (NAESB). These standards will establish communication protocols between interstate pipelines and power plant operators and transmission owners and operators. The proposed standards would require gas-fired power plant operators and natural gas pipelines to establish procedures to communicate material changes in circumstances that may affect hourly flow rates. These standards would ensure that pipelines have relevant planning information that will assist in maintaining the operational integrity and reliability of pipeline service, as well as providing gas-fired power plant operators with information as to whether hourly flow deviations can be honored. They would further improve communication by requiring pipelines to provide operational flow orders and other critical notices to electric transmission operators, including independent system operators (ISOs) and regional transmission organizations (RTOs), as well as power plant operators that sign up with connecting pipelines. These standards will ensure that operators of the electric grid can remain informed of developments on gas pipelines that can affect the reliability of electric service. This information should assist reliability coordinators in assessing the relative reliability of various gas-fired generators. FERC asked RTOs and ISOs to file their responses and proposed revisions by January 16, 2007.

 

NEB Releases Winter Outlook for Energy Markets: Canada’s National Energy Board (NEB) released its winter outlook on October 31, 2006, asserting that the natural gas and crude oil inventory levels, as well as the uncertainty of winter weather, are the key issues that will shape North American energy markets during the upcoming winter. Production recovery and the level of natural gas in storage at the end of the 2005-2006 winter placed downward pressure on prices during recent months. However, despite the falling prices this year, drilling for natural gas has remained strong. The NEB expects that demand will increase in November owing to the forecasted lower temperatures, causing natural gas prices to move up, reflecting the tighter balance. NEB expects that a normal winter could lead to Canadian upstream prices in the C$6 to C$7 per Mcf range, with continued strong drilling and production. A colder-than-average winter could cause prices to spike above C$7 per Mcf. On the other hand, a mild winter may cause prices to decrease to C$5 per Mcf or less, which could lead to a widespread decline in drilling.

 

Canadian NEB Releases Deliverability Report:  Natural gas deliverability in Canada is projected to rise from 484 million cubic meters (mcm) per day (17.1 billion cubic feet (Bcf) per day) in 2005 to 491 mcm per day (17.3 Bcf per day) by 2008, according to a new report released on October 26 by the National Energy Board (NEB).  The report, titled “Short-term Canadian Natural Gas Deliverability 2006-2008” states that decreasing production of natural gas from conventional sources will be more than offset by the growth of coalbed methane in Alberta.  Conventional gas deliverability is expected to decrease by 13 mcm per day (459 million cubic feet (MMcf) per day), or almost 3 percent, by 2008, while coalbed methane is expected to increase by 19 mcm per day (671 MMcf per day), or almost 300 percent.  The report adds that several factors could impact deliverability this winter, however, such as volatile prices, rising costs, and storage levels.  The labor market in Canada also continues to challenge the industry.  The NEB is an independent federal agency of Canada that regulates several aspects of the energy industry.      

 

Natural Gas Transportation Update: 

·         A leak on the Bluewater West Leg system offshore Louisiana caused 22 platforms to be shut-in on Monday, October 30, until further notice.  The affected platforms are owned by Columbia Gulf Transmission Company and Tennessee Gas Pipeline Company.

·         Pacific Gas and Electric Company had a systemwide Stage 2 high-inventory operational flow order (OFO) in place from Thursday, October 26, through Sunday, October 29.  The tolerance for positive daily imbalances varied between 5 and 13 percent, and penalties for exceeding the tolerance were $1 per decatherm.

·         Maintenance at the Carthage Junction Compressor Station in Panola County, Texas, caused capacity to be reduced by as much as 75,000 decatherms per day, on October 27 and 28, according to Gulf South Pipeline Company.

·         El Paso Corporation conducted routine maintenance at the Bondad Compressor Station in La Plata County, Colorado, this week, which reduced capacity to 131 MMcf per day on Tuesday, October 31 (from a base of 746 MMcf/d), and to 65 MMcf per day on Wednesday, November 1. 

·         Southern Natural Gas Company announced that starting October 26, it is lifting some of the restrictions on nonfirm storage transactions that were implemented last May because of the historically high storage inventories on its system. 

·         ANR Pipeline Company lifted restrictions on daily and overrun injections into certain storage accounts owing to recent storage activity and current projected inventory levels.  Certain customers will be allowed to inject above the current maximum Daily Injection Quantity in effect, but may not exceed the Maximum Storage Quantity level of their contract.    

·         Colorado Interstate Gas Company announced that its storage withdrawal capability is reduced by about 51 percent because of a well leak at the Fort Morgan Storage Field in Morgan County, Colorado.  Customers were limited to 49 percent of their Average Daily Withdrawal Quantity on Friday and Saturday, October 27 and 28. 

·         El Paso Corporation announced that no injections or withdrawals will be possible at its Washington Ranch Storage Facility from November 1 through 7 because of testing and maintenance work.

 

 

 Short-Term Energy Outlook