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Natural Gas Weekly Update
Natural Gas Weekly Update Text
Released: March 5, 2009
Next Release: March 12, 2009
Overview (For the Week Ending Wednesday, March 4, 2009)

  • A late winter cold spell in major population centers in the Lower 48 States this report week temporarily boosted space-heating demand in most of the country. Prices at trading locations throughout the country were slightly higher for the report week. The Henry Hub spot price increased $0.03 per million Btu (MMBtu) to $4.23.

  • At the New York Mercantile Exchange (NYMEX), trading of the March contract ended during the report week with a final or expiration price of $4.056 per MMBtu, the lowest expiration price for a near-month NYMEX contract since the October 2002 contract. Nonetheless, futures prices were generally higher for the report week. The near-term futures contract for April delivery increased 31 cents per MMBtu on the week to $4.34.

  • As of Friday, February 27, working gas in underground storage was 1,793 billion cubic feet (Bcf), which is 13.8 percent above the 5-year (2004-2008) average.

  • The price of West Texas Intermediate (WTI) crude oil increased on the week by $3.64 per barrel to $45.28, or $7.81 per MMBtu, the highest price for WTI crude oil since January 26, 2009.

NYMEX Natural Gas Futures Near-Month Contract Settlement Price, West Texas Intermediate Crude Oil Spot Price, and Henry Hub Natural Gas Spot Price Graph

More Summary Data

A major weather front entered the Midwest and the East this week, leading to slight gains in prices throughout the country. The benchmark Henry Hub price advanced on the week by less than 1 percent to $4.23. On a regional basis, spot markets along the Gulf Coast in Louisiana and East Texas each registered an average price increase of $0.08 per MMBtu, or about 2 percent. The average regional price yesterday (March 4) was $4.18 in Louisiana and $3.79 in East Texas. In the Northeast, the average regional price gained 17 cents per MMBtu to $4.85, the highest regional price in the country. Meanwhile, the lowest prices in the country continue to be found west of the Mississippi River. As of yesterday, the Midcontinent price averaged $2.84 per MMBtu, which was less than 1 percent lower on the week.

Although increased weather-related demand in the Midcontinent and Rockies allowed for higher prices there for much of the winter, prices now appear likely to trade at lower levels. Midcontinent regional pricing is now well-integrated with Rockies price trends because of increased flows between the regions. In bid week trading for April in the two regions, prices for baseload volumes fell well below $3 per MMBtu. At the Opal trading hub in Wyoming, the final bid week price was $2.53 per MMBtu, while the price for supplies off Panhandle Eastern Pipeline Company in the Midcontinent finished bid week trading only slightly higher at $2.56 per MMBtu. In addition to weather-related demand, the abundance of supplies in the Midcontinent region likely continues to be an important factor in regional prices.

Price increases in the Northeast were the highest of all regions, averaging $0.17 per MMBtu, or nearly 4 percent, in comparison with the prior week. Temperatures in the Northeast during this report week fell below normal as a late cold front moved across the region, likely boosting heating demand and supporting upward price movements. The regional average price reached as high as $9.13 per MMBtu early in the week during the coldest day of the weather front. The premium in the Northeast price over Gulf of Mexico region prices tends to increase with the occurrence of colder weather. Interstate pipelines from the Gulf to the Northeast have limited capacity to transport non-firm supplies, resulting in disparities in local supply and demand conditions. For delivery in Zone 5 (the Mid-Atlantic region) off Transcontinental Gas Pipe Line, the price gained $0.10 per MMBtu to $4.53. For delivery into the pipeline’s Zone 6 (including delivery into New York), the price increased 46 cents per MMBtu to $5.27.

Spot Prices

At the NYMEX, the futures contract for March delivery expired on February 25 at $4.056 per MMBtu, the lowest final settlement price for a near-month contract since expiration of the October 2002 contract on September 26, 2002. The March contract finished trading at less than half the final price of the March 2008 contract ($8.93) and about 46 percent of the March 2007 contract ($7.55). During its term as the near-month contract, the March contract lost 11 percent of its value, or approximately 52 cents.

During the report week, the price of the April futures contract increased 31 cents per MMBtu to $4.34, chiefly in response to colder weather and increases in the price of competing fuels, such as crude oil. Nonetheless, downward price pressure related to the domestic production outlook and the current economic downturn appeared to dampen price increases. The economic downturn has resulted in a decline in consumption, particularly in the industrial sector, with many companies announcing layoffs and closures of manufacturing plants around the country. At the end of trading yesterday, the 12-month strip, which is the average for natural gas futures contracts over the next year, was priced at $5.16 per MMBtu, an increase of about $0.22 since last Wednesday.

Wellhead Prices Annual Energy Review
More Price Data

Working gas in storage totaled 1,793 Bcf as of Friday, February 27, 2009, according to EIA’s Weekly Natural Gas Storage Report (see Storage Figure). The implied net withdrawal of 102 Bcf for the week was significantly less than both the average withdrawal of 121 Bcf over the past 5 years (2004-2008) and last year’s net withdrawal of 139 Bcf. As a result, the difference between current storage inventories and the 5-year average increased to 218 Bcf and the difference between current storage inventories and last year’s aggregate level increased to 270 Bcf.

Below average withdrawal occurred despite colder-than-normal temperatures across much of the Lower 48 States. The current economic downturn and continued domestic production strength would have limited the need for withdrawals from storage. The lower net withdrawal occurred during a week when weather was colder than normal in six of the nine Census Divisions. In particular, heating degree-days (HDDs) were above normal in the populous regions east of the Mississippi, which likely contributed to net withdrawals in the East region equaling the 5-year average. HDDs were 6 percent higher than normal for the country as a whole, according to the National Weather Service (see Temperature Maps and Data).

Storage Table

More Storage Data
Other Market Trends

Natural Gas Rig Count Declined below 1,000: The number of rigs drilling for natural gas declined to 970 for the week ended February 27, 2009, down from 1,018 in the previous report week, according to Baker-Hughes Incorporated. This number is the lowest level of natural gas rigs since March 19, 2004. Gas rigs were about 32 percent lower than the 1,418 recorded for the same week last year. The active natural gas drilling rig count has fallen precipitously since September 2008, including declines each week since the end of November 2008. Generally, natural gas rigs drilling respond to spot prices with a lag, and the most recent downward trend in rigs drilling occurred as a result of the decrease in natural gas prices that began in the summer of 2008. When natural gas prices began a steep downward trend from their recent peak in July 2008, rigs drilling also turned downward after hitting a peak of 1,606 on September 12, 2008 (see Natural Gas Rigs and Spot Prices graph). Since its relative peak of $13.31 per MMBtu in early July, the natural gas spot price at the Henry Hub has decreased 68 percent as of March 4, 2009, while natural gas rigs declined almost 40 percent from their September peak to last week’s level.

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Natural Gas Transportation Update

  • ANR Pipeline Company informed its customers that the company has restricted capacity on its Southwest Mainline to 700 MMcf per day as a result of unscheduled maintenance on the Birmingham compressor station in Iowa. The capacity restrictions were implemented on February 25 and will last through the end of today’s gas day (March 5). The pipeline also reported that unplanned engine repairs at its Joliet compressor station in Illinois resulted in a reduction of the NGPL-Joliet interconnect capacity to 90,000 decatherms (Dth) per day. This latest capacity reduction will remain in place until March 9 and is expected to curtail interruptible and firm secondary nominations.

  • Colorado Interstate Gas Company (CIG) declared force majeure as a result of an unforeseen mechanical outage at the Morton compressor station in Colorado on pipeline segment 118. Effective March 5, physical flows at the compressor station will be reduced from the regular compressor station flows of 382 MMcf per day to 360 MMcf per day. During the outage, which is expected to end by March 13, CIG expects to fulfill firm nominations through the compressor station. The pipeline did not provide any information on possible impacts to interruptible transportation service.

  • CIG also announced its storage field maintenance plan for April 2009. According to the company, all four of CIG’s storage fields will undergo scheduled maintenance for a week at a time during April. The operational limitations related to field outages will affect the injection rights of CIG's firm shippers, while interruptible service shippers will not be able to schedule any volumes. The fields affected by the maintenance are Ft. Morgan, Colorado (with a maximum injection capacity of 125 MMcf per day), Latigo, Colorado (80 MMcf per day), Boehm, Kansas (65 MMcf per day), and Flank, Colorado (55 MMcf per day).

See Weekly Natural Gas Storage Report for additional Natural Gas Storage Data.
See Natural Gas Analysis for additional Natural Gas Reports and Articles.
See Short-Term Energy Outlook for additional Natural Gas Prices, Supply, and Demand.