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Overview:  Thursday, January 22, 2004 (next release 2:00 p.m. on January 29)

Natural gas spot prices increased 10 to 60 cents per MMBtu at nearly all major trading locations in the Lower 48 States as space-heating demand remained strong amid very cold temperatures in critical gas-consuming markets. However, elevated prices of $40 per MMBtu and more in the Northeast eased closer to historical norms over the course of the week following at least a temporary reprieve from the extreme cold in the region. For the week (Wednesday-Wednesday), prices at the Henry Hub increased $0.53 per MMBtu, or 9 percent, to $6.27. The price of the NYMEX futures contract for February delivery at the Henry Hub fell approximately 24 cents per MMBtu to settle yesterday (Wednesday, January 21) at $6.150. Natural gas in storage was 2,258 Bcf as of Friday, January 16, which is 9.3 percent above the 5-year average. The spot price for West Texas Intermediate (WTI) crude oil increased $0.91 per barrel or about 2.6 percent since last Wednesday to trade yesterday at $35.53 per barrel or $6.13 per MMBtu.



After declining for much of the period from January 9 through January 16, prices at most trading locations surged on Tuesday, January 20, when traders returned to colder-than-expected weather following the Martin Luther King, Jr. holiday weekend. The upward pressure on spot prices continued through yesterday’s (January 21) trading session, resulting in net price increases of 5-10 percent in the Gulf Coast region compared with the previous Wednesday (January 14). The Henry Hub spot price has gained 87 cents per MMBtu, or 16 percent, in the past two trading days, and a net 53 cents per MMBtu since last Wednesday. In the Northeast, interstate pipelines continued to experience near-peak operating conditions through much of the week, although constraints appear to be easing (see Other Market/Industry Trends below). As a result, gas buyers resorting to the spot market in the region for incremental supply early in the week faced high prices. In New England, the spot price for delivery off the Algonquin Gas Transmission pipeline system was as high as $64.22 per MMBtu last Wednesday, but as restrictions have been relaxed it has fallen to trade in a $7-$8 range. On the week, the price off Tennessee Gas Pipeline in New England decreased $42.61 per MMBtu to trade at $7.17 yesterday. Price fluctuations were less severe in the Midwest, where the Chicago citygate price increased to $6.27 per MMBtu, a net change of $0.51 per MMBtu, or 8.8 percent, on the week.



At the NYMEX, the futures contract for February delivery lost $0.24 per MMBtu on the week to settle at $6.15 yesterday (January 21), owing to forecasted warmer weather as well as relatively high levels of natural gas in storage for this time of year. The daily settlement for the February contract on Thursday, January 15, settled at $5.845 per MMBtu after storage numbers for underground inventories were released. The Thursday closing price was the February contract’s lowest settlement since becoming the near-month contract on December 30, 2003. The March 2004 contract, which is currently the highest priced contract for this winter, closed yesterday, at $6.217 per MMBtu, down 28 cents on the week. Since the previous Wednesday (January 14), the 12-month strip, which is the average of futures prices for the coming year, dropped nearly 12 cents per MMBtu to $5.616.


Estimated Average Wellhead Prices








Price ($ per Mcf)







Price ($ per MMBtu)







Note:  The price data in this table are a pre-release of the average wellhead price that will be published in forthcoming issues of the Natural Gas Monthly.  Prices were converted from $ per Mcf to $ per MMBtu using an average heat content of 1,025 Btu per cubic foot as published in Table A2 of the Annual Energy Review 2001.

Source:  Energy Information Administration, Office of Oil and Gas. 



Working gas in storage was 2,258 Bcf or 9.3 percent above the 5-year average as of January 16, according to EIA’s Weekly Natural Gas Storage Report (See Storage Figure).  Implied net withdrawals were 156 Bcf, or about 5.5 percent less than the previous 5-year average withdrawal of 165 Bcf. Although this is the largest net withdrawal of the 2003-2004 winter to date, the withdrawal is 29 percent less than last year’s pull of 219 Bcf. In most regions outside of the Northeast, gas customer-weighted heating degree days (HDD), as measured by the National Weather Service, fell far below normal during the week (See Temperature Map) (See Deviations Map).  HDDs were 10 percent below normal in the high-gas-consuming East North Central Census Division, which includes Midwest cities such as Chicago. HDDs in the high-gas-consuming New England and Middle Atlantic Census Divisions were 33 and 25 percent above normal, respectively, which likely contributed to a relatively high net withdrawal of 115 Bcf in the Consuming East region. The prior 5-year average withdrawal for the region was 111 Bcf.



Other Market Trends:

Natural Gas Supply Outlook Lowered in Latest EIA Long-Term Forecast:  In its Annual Energy Outlook for 2004 with Projections to 2025 (AEO2004), released Wednesday, January 14, 2004, the Energy Information Administration (EIA) projects that total gas supply by 2025 will increase to 31.1 trillion cubic feet (Tcf), which is 3.3 Tcf less than was projected in AEO2003.  The revised total supply outlook hinges on lower expectations for domestic production and Canadian imports.  Domestic production grows to 24.1 Tcf in 2025, or 2.7 Tcf less than projected last year.  Domestic production growth will depend more on unconventional sources, because prospects for conventional onshore production are affected by higher expected exploration and development costs, fewer new discoveries and thus fewer additions to reserves.  Another major change in the supply picture from AEO2003 is a reduced role for imports of gas from Canada beyond 2010.  The projection now is for a gradual decline beginning in 2010 to 2.6 Tcf in 2025, which contrasts with the AEO2003 projections of net imports from Canada rising from 3.7 Tcf in 2010 to 4.8 Tcf in 2025.  EIA now projects that LNG net imports will overtake net Canadian imports by 2015.  LNG’s share of net imports is projected to grow from less than 5 percent in 2002 to 39 percent (2.2 trillion cubic feet) in 2010 and 66 percent (4.8 trillion cubic feet) in 2025.  Gas from Alaska via a still-to-be-built long-line pipeline is expected to combine with unconventional domestic production and LNG imports to provide most of the nation’s future supply growth.  But total supply growth is not expected to offset the impacts of resource depletion and increased demand, leading to an average annual growth in wellhead natural gas prices of nearly 2 percent from 2010 to 2025. 


Major Accident Shuts Key Algerian LNG Facility:  An explosion and resulting fire at a liquefied natural gas (LNG) facility in the Algerian port of Skikda on Monday, January 19, killed 27 and injured at least 74 and caused an immediate halt to its operations.  The port of Skikda is located on the Mediterranean coast about 300 miles east of the capital city of Algiers.  The so-called GL1/K LNG complex, operated by Sonatrach Petroleum, consists of six LNG liquefaction trains with a combined capacity of about 680 million cubic feet per day, and accounts for about 23 percent of Algeria’s total export capacity.  In a statement released Tuesday, Sonatrach noted that three of the six LNG trains were heavily damaged by the intense fire that followed the explosion, the cause of which is yet to be determined.  Algeria is currently the third largest supplier of LNG to the United States, behind Trinidad and Nigeria.  According to the latest data published by the Energy Information Administration, through the first nine months of 2003 Algeria had supplied about 37 Bcf of LNG to the United States, or about 10 percent of total LNG imports.  According to press reports, the extent of the damage to the facility is still unclear, so it is unknown at this time when the facility will resume operations and at what capacity.     


Northeast Pipeline Restrictions Ease Following Weather Reprieve: Interstate pipeline operating conditions appeared to be easing slightly this week following recent peak conditions that limited supply options. Operational Flow Orders (OFOs), which can vary significantly in severity, were issued by a variety of pipelines last week during the record cold snap in the Northeast. When these restrictions are in place, customers without firm contracted capacity on the pipeline generally are interrupted and cannot access Gulf supplies because transportation through the pipeline grid is not available. Thus, prices in the Northeast and Gulf region become disconnected as customers in the Northeast without firm contracted capacity seek incremental supplies only in local market areas. The result last week was that prices at some Northeast trading locations spiked to $45 per MMBtu or more for gas deliveries the following day. After cutting all non-firm deliveries last week, Texas Eastern Transmission (TETCO) has again started interruptible deliveries in the pipeline’s Northeast market area. This includes areas in Pennsylvania and New Jersey. Prices in TETCO’s market area, known as M3, rose as high as $41 per MMBtu on January 14, but traded yesterday at $7.40. Additionally, Algonquin Gas Transmission this week lifted a Critical Notice limiting imbalance tolerances to 2 percent, but left in place a ban on accepting nominations for due-shipper imbalance make-ups. Algonquin last week had notified parties that any quantity of gas outside the 2 percent variance would be charged a $15/Dth penalty. Prices on the pipeline, which serves much of New England (including the Boston area) rose to more than $50 per MMBtu last week, but have since fallen to trade in a range of $7-$8 per MMBtu. Tennessee Gas Pipeline also had a variety of restrictions in place recently, but has since ended an OFO balancing alert for its Northeast market areas. However, the pipeline reminded customers that demand remains high and flows should continue to match scheduled volumes. After trading as high as $49 per MMBtu last week, the price for delivery off Tennessee has dropped to $7.17.



Natural gas prices increased 6 percent or more as very cold temperatures lingered in many parts of the country. Natural gas in storage declined to 2,258 Bcf as of January 16, leaving inventories more than 9 percent above the 5-year average.


Natural Gas Summary from the Short-Term Energy Outlook