Natural Gas

• Warmer weather moved into major population centers this report week, limiting demand related to space heating for much of the country. Prices declined, with the biggest decreases occurring at markets in the Rocky Mountains and the Midcontinent. During the report week, the Henry Hub spot price decreased $0.15 to $4.76 per million Btu (MMBtu).
  
• At the New York Mercantile Exchange (NYMEX), futures prices also decreased. The futures contract for April delivery decreased by $0.10 on the week to $4.76 per MMBtu.
  
• As of Friday, February 26, working gas in underground storage was 1,737 billion cubic feet (Bcf), which is 1.2 percent above the 5-year (2005-2009) average. The implied net withdrawal from storage was 116 Bcf.
  
• The price of West Texas Intermediate (WTI) crude oil increased on the week by $1.16 per barrel to $80.91, or $13.95 per MMBtu. Wednesday’s closing price is the highest for WTI crude in 7 weeks.

Although the report week began with a major winter storm in the Northeast, the weather has since moderated for much of the country. The resulting decrease in space-heating demand in the residential and commercial sectors was as much as 7.7 Bcf per day from Thursday, February 25, to Wednesday, March 3, according to Bentek Energy LLC. Price declines occurred throughout most of the country, although most were less than $0.25 per MMBtu. The Henry Hub natural gas spot price decreased in 4 out of the 5 trading days this report week, closing at $4.76 per MMBtu on Wednesday, March 3. This price was 3 percent lower than the average price on the previous Wednesday, and the lowest year-to-date price at the Henry Hub. The current Henry Hub price is 22 percent lower than the price of $6.09 per MMBtu at the beginning of the year. Elsewhere in States surrounding the Gulf of Mexico, price decreases during the week were generally between $0.10 and $0.20 per MMBtu. The price at the Houston Ship Channel in East Texas decreased by $0.10 on the week to $4.75 per MMBtu, while the price at Transcontinental Gas Pipe Line (Transco) Station 65 in Louisiana decreased by $0.16 to $4.80 per MMBtu. The lone exception to widespread regional declines was a $0.17-increase in the price for supplies delivered to Florida.

A strong outlook for U.S. supplies is likely the primary factor leading to price declines over recent weeks. Domestic production, specifically supplies from unconventional gas fields such as the Marcellus Shale in the Northeast/Appalachia region and the Haynesville Shale in Louisiana, has not declined substantially despite reductions in overall rig counts compared with this time last year. According to the February edition of the EIA’s Natural Gas Monthly (NGM), marketed production in December totaled 60.3 Bcf per day, a decrease of less than a percent from November and an increase of 1.5 percent compared with December 2009 (See Other Market Trends below). Imports of natural gas have also been strong recently. During the report week, net Canadian imports were 10 percent higher than the same week in 2009, partly aided by flows from the new Canaport Liquefied Natural Gas (LNG) terminal in Nova Scotia. The pace of deliveries of U.S. LNG imports in recent weeks has also increased considerably in comparison with this time last year. Sendout from U.S. LNG import terminals has averaged 2.0 Bcf per day during the first 2 months of the year, compared with 1.1 Bcf per day during the same time period in 2009. A greater number of LNG cargoes are being directed to the United States following production increases in countries such as Russia and Qatar.

In the Northeast, prices decreased by as much as 4 percent on the week, as temperatures in the region increased. All points in the Northeast region posted declines of more than $0.10 per MMBtu on the week. For delivery in Zone 6 into New York off Transco, the price declined by $0.20 per MMBtu to an average of $5.29 by the end of the report week. This price was the lowest at this market center in 2010, and just $0.47 higher than the Henry Hub price. In recent years, the Northeast’s price premium over Gulf of Mexico regional prices has typically widened significantly with the advent of colder weather, likely because of a lack of alternatives for transportation of supplies into the region during periods of peak demand. Although temporary price increases have occurred in the Northeast this year, a lower price spread between the Northeast and other markets may be developing because of more supply options for the region. These options include growing supplies in the Marcellus Shale, access to Rockies supplies at Lebanon, Ohio, through the Rockies Express Pipeline (REX), as well as regasified LNG from the Canaport LNG terminal in Canada. In fact, the average differential between the New York and Henry Hub price was just $1.93 per MMBtu during the first 2 months of 2010, compared with $3.11 per MMBtu during the same time period in 2009.

Prices at the majority of markets west of the Mississippi River decreased between 4 and 5 percent. The price at the Opal, Wyoming, trading point decreased by $0.22 on the week to $4.54 per MMBtu. Consistent with other regional trends, this price was also the lowest average price at this market center in 2010. However, prices in the Rocky Mountains have generally remained at a higher level relative to prices in other parts of the country. During the first 2 months of 2010, the average difference between the Opal price and the Henry Hub price was $0.33 per MMBtu, significantly less than the average of $1.53 per MMBtu during the same time period in 2009. Midcontinent and Rocky Mountain prices are now well-integrated, in part because of increased pipeline capacity between the regions from pipeline projects such as REX. The price for supplies off Panhandle Eastern Pipeline Company in the Midcontinent finished the week at $4.61 per MMBtu, a decrease of $0.21 from the previous Wednesday.

At the NYMEX, the price of the near-month contract (for April delivery) decreased $0.10 during the report week to $4.76 per MMBtu. The decrease was attributable chiefly to warmer temperatures moving into consuming regions of the country. Downward price pressure also appears related to a strong domestic production outlook. The April 2010 contract is currently priced about 31 percent higher than the expiration price of $3.63 per MMBtu for the April 2009 contract. However, the April 2008 contract expired at $9.58 per MMBtu, or about double the current price of the April 2010 contract. 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 $5.33 per MMBtu, a decrease of about $0.09, or 1.7 percent, since last Wednesday.

Working gas in storage decreased to 1,737 Bcf as of Friday, February 26, according to EIA’s Weekly Natural Gas Storage Report (see Storage Figure). The implied net withdrawal of 116 Bcf was 6 percent below the 5-year average (2005-2009) withdrawal of 124 Bcf for the same report week, and 15 percent above last year’s net withdrawal of 101 Bcf. Significantly warmer-than-normal temperatures in the Middle Atlantic and New England Census Divisions, where space-heating demand for natural gas is particularly intense, may have contributed to the below-normal rate of withdrawals during the report week. U.S. working gas inventories are 71 Bcf below year-ago levels and 21 Bcf above the 5-year average level.

On a regional basis, working gas stocks in the Producing region were 130 Bcf below last year’s level, accounting for the year-over-year storage deficit in the lower 48 States. At 580 Bcf, working gas in storage in the Producing region was 18 percent below the year-ago level of 710 Bcf, while the East and West regions were 7 percent and 1 percent, respectively, above year-ago levels. Working gas stocks began the heating season with levels well above the 5-year average. Significantly colder-than-normal temperatures in the Producing region throughout the current heating season likely contributed to the year-over-year storage deficit. The West remains the only region in the lower 48 States with a surplus relative to the 5-year average, as natural gas demand in the region during the current heating season has not been sufficient to significantly reduce the 56-Bcf surplus relative to the 5-year average that prevailed as of January 1, 2010.

Temperatures were generally colder than normal in the Census Divisions outside of the Middle Atlantic and New England Census Divisions during the week ended February 25, 2009. Based on the National Weather Service’s degree-day data, temperatures in the lower 48 States during the week were, on average, about 8 percent colder than normal and 2 percent warmer than last year’s levels (see Temperature Maps and Data). Temperatures in the heavy gas-consuming New England and Middle Atlantic Census Divisions, were 19 percent and 7 percent warmer than normal, respectively. The East North Central Census Division was 2 percent colder than normal. Elsewhere in the lower 48 States, temperatures ranged between 9 percent and 38 percent colder than normal.

Natural Gas Consumption Rises to 74.3 Bcf per day in December 2009. On March 2, EIA released the February 2010 Natural Gas Monthly (NGM), which includes data through December 2009. Delivered volumes of natural gas to consumers rose to 74.3 Bcf per day, up from 54.1 Bcf per day in November 2009 and 71.6 Bcf per day in December 2008. Much of the jump in consumption was attributable to the weather-related 12-Bcf per day increase in residential consumption from November 2009 to December 2009. However, deliveries to industrial, commercial, and electric power customers also increased from November to December. Heating degree-days (HHDs) in December totaled 937, which is higher than both the 2008 level of 908 and the 30-year normal level of 884. Though HDDs rose year-over-year, residential consumption fell slightly, from 24.8 Bcf per day in December 2008 to 24.5 Bcf per day in December 2009. NGM data indicate that wellhead prices rose from $3.64 per thousand cubic feet (Mcf) in November to $4.44 per Mcf in December. Industrial prices rose as well, while citygate, residential, and commercial prices fell. According to the NGM, U.S. marketed production fell from 60.7 Bcf per day in November 2009 to 60.3 Bcf per day in December.

Natural Gas Annual 2008 shows highest marketed production since 1974. EIA released the Natural Gas Annual 2008 (NGA2008) on March 2, which provides information on the supply and disposition of natural gas in the United States. Total U.S. marketed production increased for the third consecutive year in 2008, reaching 21.2 trillion cubic feet (Tcf) an increase of 5.2 percent over the 2007 total. A 798-Bcf annual increase in Texas’ production more than offset the decline in the Gulf of Mexico in 2008. The NGA2008 also provides summary production, transmission, storage, deliveries, and price data by State for 2004 through 2008. According to the NGA2008, U.S. natural gas prices increased across all sectors throughout 2008 compared with 2007 levels. Although the 2008 hurricane season was the most active since 2005, natural gas prices showed relatively little response to Hurricanes Gustav and Ike. Natural gas consumption rose to 23.2 Tcf in 2008. Temperatures during the winter of 2008 were colder than in 2007, with 5.6 percent more heating degree-days. Colder weather contributed to residential natural gas consumption rising 3.2 percent to 4.9 Tcf. Commercial consumption also rose in 2008 by 4.1 percent to 3.1 Tcf, while consumption in the industrial sector increased less than 1 percent to 6.7 Tcf. Annual electric power sector consumption decreased for the first time since 2003, falling 2.5 percent to 6.7 Tcf, likely as a result of the 8.7-percent decrease in cooling degree-days in 2008.

EIA Forecasts Growth in Shale Production. EIA Administrator Richard Newell discussed prospects for natural gas production growth from shale formations at Flame—European Gas Conference on March 2, 2010, in Amsterdam, the Netherlands. Newell discussed the history of shale gas production, as well as shale prospects both in the United States and worldwide. Newell’s presentation, “Shale Gas: A Game Changer for U.S. and Global Gas Markets?” is available here: http://www.eia.doe.gov/neic/speeches/newell030210.pdf.

• On February 25, Rockies Express Pipeline (REX) reported that it completed repairs to a weld defect at the Cheyenne compressor station in Colorado. REX lifted the associated force majeure, which had been in place since Monday, February 22. The force majeure resulted in service interruption and decreased nominated quantities at three of the pipeline’s segments between February 22 and 26, 2010.
  
• In another announcement, REX reported that it has been performing maintenance at its Wamsutter Echo Springs booster station in Wyoming since March 2. The maintenance, which is expected to be complete by the end of today’s (March 4) gas day, resulted in curtailments at the receipt point associated with the booster station.
  
• Hardy Storage Company, LLC declared critical storage days for March 1 and 2 at its Hardy storage facility in West Virginia. Based on storage withdrawal capacity and firm storage withdrawal requirements, Hardy required that all available storage withdrawals meet firm service obligations.
  
• Texas Eastern Transmission, LP reported on March 2 that its Circleville, Ohio, compressor station has experienced an outage and repair efforts to restore this compressor station to full capacity are underway. Texas Eastern estimates the resulting capacity reduction at approximately 120 million cubic feet (MMcf) per day through and downstream of Circleville. According to BENTEK Energy, the 30-day average flow at the compressor station prior to the outage was 632 MMcf per day. This reduction in capacity is not expected to result in any interruption of firm services.

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.