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Weekly Natural Gas Storage
U.S. Natural Gas Imports and Exports: 2004
Residential Natural Gas Prices: What Consumers Should Know
An Assessment of Prices of Natural Gas Futures Contracts As A Predictor of Realized Spot Prices at the Henry Hub
Overview of U.S. Legislation and Regulations Affecting Offshore Natural Gas and Oil Activity
Changes in U.S. Natural Gas Transportation Infrastructure in 2004
Major Legislative and Regulatory Actions (1935 - 2004)
U.S. LNG Markets and Uses: June 2004
Natural Gas Restructuring
Previous Issues of Natural Gas Weekly Update
Natural Gas Homepage
EIA’s Natural Gas Division Survey Form Comments

Overview:  Thursday, April 6 (next release 2:00 p.m. on April 13, 2006)

Despite the close of the traditional heating season on March 31 with relatively high volumes of natural gas remaining in storage, spot prices increased at most market locations in the Lower 48 States. For the week (Wednesday-Wednesday, March 29-April 5), however, the spot price at the Henry Hub decreased 28 cents per MMBtu, or about 4 percent to $6.88. In contrast to the mixed price patterns on the spot markets, the prices of futures contracts at the New York Mercantile Exchange (NYMEX) for delivery through next heating season all declined on the week. The futures contract for May delivery at the Henry Hub yesterday (Wednesday, April 5) settled at $7.069 per MMBtu, which is 39 cents less than last Wednesday’s price. Natural gas in storage decreased to 1,695 Bcf as of March 31, ending the heating season at 63 percent above the 5-year average. The spot price for West Texas Intermediate (WTI) crude oil increased 76 cents per barrel or about 1 percent since last Wednesday to $66.76 per barrel or $11.51 per MMBtu.




Natural gas spot prices increased at most market locations on the week, but generally decreased in the South Texas and Louisiana regions. Most price increases in the Lower 48 States were limited to about 25 cents per MMBtu, while decreases ranged up to 33 cents on the week. The largest price increases occurred in the Northeast, which experienced cold temperatures and flurries in some areas, leading to average increases of more than 20 cents per MMBtu to an average price of $7.72 per MMBtu. At the New York citygate off Transcontinental Gas Pipeline, the spot price increased 38 cents or more than 5 percent per MMBtu to $7.94, which was the highest week-on-week increase in the Lower 48 States. Prices generally declined for the week in the South Texas and Louisiana producing regions. The Henry Hub spot price fluctuated during the week, but decreased 28 cents or about 4 percent per MMBtu since last Wednesday, falling to $6.88 per MMBtu in yesterday’s trading. In South Texas, the price for next day delivery off the Natural Gas Pipeline (NGPL) decreased 33 cents per MMBtu to $6.50.



At the NYMEX, the May 2006 contract became the near-month contract last Thursday, March 30, and gained 3.1 cents per MMBtu on its first day as the near-month contract. On the week, however, the May 2006 contract decreased 39 cents, or about 5 percent, settling at $7.069 per MMBtu yesterday. The closing price for the near-month contract was nearly 19 cents per MMBtu higher than the price commanded in the spot market yesterday. Prices for all the futures contracts through the end of the next heating season have decreased on the week by an average of 24 cents. Despite the decreases, they remain in contango.  Futures prices show an increasing trend through the January 2007 contract, which traded yesterday at $10.894 per MMBtu. The January 2007 contract as of yesterday was priced $4.01 per MMBtu higher than gas in the current Henry Hub spot market. The 12-month strip, which is the average price for contracts over the next year (May 2006 through April 2007), increased by 23 cents per MMBtu to end the week at $8.847.


The 2005-2006 heating season (November 1-March 31) was marked by several different record-setting and near record-setting events. The average spot price at the Henry Hub exceeded levels of the past two heating seasons by 45 and 68 percent, respectively, which is more than $2.86 per MMBtu above the level of the past two seasons. Factors contributing to the recent relatively high prices include production disruptions resulting from hurricanes Katrina and Rita, limited growth in net imports with a year-on-year decline in LNG imports, high petroleum prices, and larger stocks of gas-burning equipment in households and for electric power generation. Hurricane-related production disruptions in the Gulf of Mexico led to large increases in the Henry Hub spot price. Prior to the heating season (during September and October 2005), spot prices reached as high as $15.27 per MMBtu. The price averaged $10.31 per MMBtu in November 2005 and then once again peaked in mid-December at $15.40 per MMBtu, which is second to the record of $18.85 on February 25, 2003.  Thereafter, the Henry Hub spot price generally declined until mid-March when it bottomed out and since then has remained fairly stable. The decrease in the Henry Hub spot price undoubtedly resulted from warmer-than-normal weather during the 2005-2006 heating season and continuing production recovery after the hurricanes. On the whole, temperatures during the 2005-2006 heating season were warmer than normal and warmer than last year for the same 5-month period, as measured by gas-customer-weighted heating-degree days (HDDs) published by the National Weather Service. Four of the five heating-season months were warmer than normal. Temperatures in January 2006 were the highest on record, and overall, none of the Lower 48 States had below average temperatures, while 15 States had record high temperatures for the month. December 2005 was the only month in the 2005-2006 heating season that recorded colder-than-normal temperatures.  Similarly, December 2005 and February 2006 were the only 2 months that had colder temperatures than those of the previous year, exceeding last winter’s HDDs by 7.8 and 8.0 percent, respectively. Overall, temperatures were 8.6 percent warmer than normal for the heating season.


Another factor pulling prices down during the heating season was the ongoing post-hurricane recovery in the Gulf of Mexico.  As of yesterday, April 5, the Minerals Management Service (MMS) reported that 1.36 Bcf per day or 13.5 percent of Gulf production remained shut in. The end-of-season daily production shut-ins were significantly lower than those early in the heating season, when more than 52 percent of the daily Gulf of Mexico production was shut in, which is the equivalent of 10.4 percent of U.S. production. The cumulative shut-in gas production from late August to April 5 was 711.6 Bcf, amounting to almost 4 percent of the annual U.S. natural gas production. The volumes of natural gas in storage were affected greatly by economic incentives posed by the unusually large differences between futures contract prices and the prevailing spot prices.  These pervasive differences motivated owners of gas in storage to refrain from withdrawing gas.  In combination with the warmer-than-normal temperatures during the 2005-2006 heating season, the heating season ended with a very large volume of natural gas remaining in underground storage. At the beginning of the 2005-2006 heating season (November 1), working gas in underground storage was 3,194 Bcf, which was 108 Bcf or 3.3 percent lower than the volumes at the onset of the 2004-2005 heating season, and 17 Bcf or 0.5 percent higher than the 5-year average volume of 3,177 Bcf. However, working gas in storage as of March 31, 2006, was 654 Bcf or 62.8 percent above the 5-year average.


Recent Natural Gas Market Data


Estimated Average Wellhead Prices








Price ($ per Mcf)







Price ($ per MMBtu)







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.



Working gas in underground storage decreased to 1,695 Bcf as of Friday, March 31, according to EIA’s Weekly Natural Gas Storage Report. Inventories as of the end of the official heating season (November 1-March 31) stand 654 Bcf, or 62.8 percent, above the preceding 5-year (2001-2005) average of 1,041 Bcf (See Storage Figure), and they are 447 Bcf, or 35.8 percent, higher than last year’s level of 1,248 Bcf. The implied net change for the week of 10 Bcf is 26 percent lower than the 5-year average implied net withdrawal of 14 Bcf  and contrasts with last year’s net injection of 1 Bcf for the same week. During the week ending March 30, 2006, the weather for the country as a whole was slightly more than 2 percent colder than normal, as measured by the National Weather Service HDDs, and almost 6 percent colder than last year. In the East North Central region, which includes Chicago and other Midwest population centers with significant space heating demand, temperatures were more than 2 percent colder than normal and about 14 percent colder than last year. On the other hand, New England, the Middle Atlantic, and West North Central Census Divisions experienced temperatures that were warmer than normal.  The coldest temperature deviations from normal were recorded in the East South Central and South Atlantic Census Regions, where temperatures were 31 and 37 percent colder than normal, respectively. (See Temperature Maps) The colder-than-normal temperatures that prevailed across much of the Lower 48 States maintained some space-heating demand.  There was a 15-Bcf withdrawal from the storage facilities in the East region. The West and the Producing regions both recorded net injections for the week. At the end of the 2005-2006 heating season, there was 1,695 Bcf of natural gas remaining in storage, which is the highest volume since 1991, when the heating season ended with 1,912 Bcf of natural gas in underground storage.  While some storage operators may penalize gas owners for rolling over an excess amount of gas into the injection season, there is anecdotal evidence that some gas owners will accept the penalties, as in some cases, it would cost more to replace the gas in storage later than the penalties themselves.


Other Market Trends:

Active 2006 Atlantic Hurricane Season Projected:  The 2006 Atlantic hurricane season is expected to be much more active than the average 1950-2000 season according to forecasts by Colorado State University’s Tropical Meteorology Project.  Updated forecasts were released on Tuesday, April 4, 2006, in a report by Philip J. Klotzbach and William M. Gray titled, “Extended Range Forecast of Atlantic Seasonal Hurricane Activity and U.S. Landfall Strike Probability for 2006” with information obtained through March 2006.  The authors expect that net tropical cyclone activity in 2006 will be 195 percent of the long-term (1950-2000) average with 17 named storms (compared with an average of 9.6), 9 hurricanes (compared with 5.9), and 5 intense hurricanes (compared with 2.3).  The forecasted activity in 2006 is less than the 2005 level, however, which had 27 named storms, 15 hurricanes, and 7 intense hurricanes, including Hurricanes Katrina and Rita. Those two storms shut in 711 Bcf of natural gas as of April 5, 2006, which is equivalent to almost 4 percent of yearly U.S. natural gas production.  The report also predicts a significantly above-average probability that at least one major hurricane (category 3-4-5) will strike land on various coastal areas in 2006.  The probability is 64 percent that a hurricane would make landfall on the U.S. East Coast (compared with a 31 percent average for the last century), 47 percent on the Gulf Coast (compared with 30 percent), and 81 percent on the entire U.S. coastline (compared with 52 percent).   The increased hurricane activity forecasts are mainly because of warm sea surface temperatures in the Atlantic Ocean combined with weak or neutral La Nina conditions and cooler El Nino Southern Oscillation conditions. 


Estimates of British Columbia Natural Gas Resources Have Increased:  Canada’s National Energy Board (NEB) and the British Columbia Ministry of Energy, Mines and Petroleum Resources (MEMPR) released a report on March 31, 2006, describing a revised outlook for British Columbia’s conventional gas resources.  The report, titled “Northeast British Columbia’s Ultimate Potential for Conventional Natural Gas,” found that the total ultimate potential for northeast British Columbia, including natural gas already produced, is 52 trillion cubic feet (Tcf), which is an increase of 1 Tcf from the 1994 estimate of 51 Tcf.  Ultimate potential for natural gas is a science-based estimate of the total amount of conventional gas in the province and is an important indicator in predicting future supply.  Since this estimate includes what has been produced to date, the report estimates that the remaining natural gas available for future demand is 35 Tcf.  Based on the current annual production of 0.95 Tcf, the estimate represents about 37 years of production. The report also notes that there is potential for additional conventional and unconventional resources elsewhere in British Columbia, as well as noting that the northeast part of British Columbia is not as mature as the Alberta portions of the basin.  In 2003, British Columbia provided about 15 percent of Canada’s total production. Canada provides about 25 percent of total North American gas production.


A Record Royalty-in-Kind Sale of Natural Gas: On April 3, 2006, the Minerals Management Service (MMS) announced that a record volume of royalty in kind (RIK) gas produced from Federal leases in the Gulf of Mexico was sold to nine companies during a recent gas sale.  The sale was concluded in mid-March and delivery of the RIK gas started on April 1, 2006.  The sale consisted of 118 Bcf of RIK gas to be delivered over 7-month or 12-month terms.  This volume is equivalent to 509,800 MMBtu per day and will be delivered to 14 offshore pipelines originating in the Gulf of Mexico.  The sale represents records in terms of the total volume of RIK gas sold and the number of bids received, as well as the total number of companies who made the bids.  The 127 offers came from a total of 21 companies for the 14 sales.  The previous record volume occurred a year ago when the sale of 485,400 MMBtu per day of RIK gas drew 126 offers. The RIK program is intended to reduce regulatory costs and reporting requirements, as well as to shorten the compliance cycle and make the auditing process simpler. With this most recent sale, MMS will be delivering more than 700,000 MMBtu of Federal royalty gas every day starting April 1.


Natural Gas Transportation Update: 

·        Five receipt points continue to be shut-in after Southern Natural Gas Company experienced an unscheduled outage on its Breton Island line offshore southeast Louisiana on March 22.  The company estimates that repairs could take several months. 

·        Columbia Gas Transmission Corp. held an open season auction through 9 a.m. on April 5 of 64,000 Dekatherms per day of available capacity in the area of Rockville, Maryland.  

·        Natural Gas Pipeline Company of America announced that two receipt points have been shut-in and are unavailable for scheduling after identifying a leak on Monday, April 3, on a segment in Latimer County, Oklahoma.

·        Florida Gas Transmission Company declared an Overage Alert Day for its customers on Monday, April 3, owing to warmer weather being forecasted for Florida.  The overage alert carries a 25-percent tolerance, meaning that shippers must stay within 25 percent of their scheduled volumes. 

·        Gulf South Pipeline Company will have a force majeure in effect during 6 days of scheduled maintenance starting Tuesday, April 4, in the Lake Charles, Louisiana, area.  The maintenance will affect service at nine locations in the area.

·        During post-hurricane inspections, Trunkline Gas Company discovered that an offshore Louisiana lateral shifted from its pre-storm location.  Production will be cut on the lateral, which runs from Ewing Bank 305 to Grand Isle 82, until further information is available on any damage.  



 Short-Term Energy Outlook










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